Exhibit 99.3

DEPI, Dominion Reserves and DTI Exploration

and Production

Combined Financial Statements and for the quarterly period ended March 31, 2010

CONTENTS

	Page Number
Combined Statements of Income for the three months ended March 31, 2010 and 2009	3
Combined Balance Sheets at March 31, 2010 and December 31, 2009	4
Combined Statements of Cash Flows for the three months ended March 31, 2010 and 2009	6
Notes to Combined Financial Statements	7

2

Dominion Exploration & Production

Combined Statements of Income

(Unaudited)

Three Months Ended March 31,	2010			2009
(thousands)
Operating Revenue
Affiliated sales, net	$	121,337		$	76,111
Other		10,486			11,888
Total operating revenue	$	131,823		$	87,999
Operating Expenses
Production (lifting)		18,017			16,379
General and administrative:
Affiliated services		4,741			4,799
Other		4,965			2,870
Ceiling test impairment		57,869			282,775
Depreciation, depletion and amortization		16,524			21,762
Total operating expenses		102,116			328,585
Income (loss) from operations		29,707			(240,586	)
Other Expense
Net interest expense (income):
Affiliated		8,655			8,838
Other		(1,141	)		(649	)
Total other expense		7,514			8,189
Income (loss) before income taxes		22,193			(248,775	)
Income taxes (benefit)		15,171			(98,840	)
Net Income (Loss)	$	7,022		$	(149,935	)

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

3

Dominion Exploration & Production

Combined Balance Sheets

(Unaudited)

	March 31, 2010			December 31, 2009
(thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	561		$	36
Accounts receivable:
Customer		12,159			8,665
Affiliate		83,178			27,534
Other receivables (less allowance for doubtful accounts of $4,257 and $4,909)		4,086			3,392
Affiliated derivative assets		9,092			45,655
Deferred income taxes		5,743			—
Prepayments		710			7,309
Other		2,326			3,405
Total current assets		117,855			95,996
Investments		926			925
Property, Plant and Equipment (full cost method)
Proved properties		1,694,850			1,668,586
Unproved properties		7,900			8,416
Other		6,351			6,344
Total property, plant and equipment		1,709,101			1,683,346
Accumulated depreciation, depletion and amortization		(751,101	)		(678,476	)
Net property, plant and equipment		958,000			1,004,870
Deferred Charges and Other Assets
Affiliated employer benefit assets		22,873			20,240
Affiliated derivative assets		—			3,131
Noncurrent income taxes receivable and other assets		30,079			32,069
Total deferred charges and other assets		52,952			55,440
Total assets	$	1,129,733		$	1,157,231

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

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(Unaudited)

	March 31, 2010			December 31, 2009
(thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	31,698		$	36,282
Payables to affiliates		10,725			2,090
Affiliated current borrowings		113,651			115,579
Accrued interest, payroll and taxes		53,734			40,723
Deferred income taxes		—			9,212
Other		20,523			19,981
Total current liabilities		230,331			223,867
Long-Term Debt
Affiliated notes payable		528,500			528,530
Total long-term debt		528,500			528,530
Deferred Credits and Other Liabilities
Deferred income taxes		252,526			266,079
Asset retirement obligations		124,651			122,587
Affiliated employer benefit liabilities		28,287			26,990
Other		23,180			23,949
Total deferred credits and other liabilities		428,644			439,605
Total liabilities		1,187,475			1,192,002
Commitments and Contingencies (see Note 10)
Common Shareholders’ Equity
Common equity		109,444			115,608
Parent investment in DTI producing activities		(23,502	)		(27,457	)
Retained deficit		(147,933	)		(151,827	)
Accumulated other comprehensive income		4,249			28,905
Total common shareholders’ equity		(57,742	)		(34,771	)
Total liabilities and shareholders’ equity	$	1,129,733		$	1,157,231

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

5

Dominion Exploration & Production

Combined Statements of Cash Flows

(Unaudited)

Three Months Ended March 31,	2010			2009
(thousands)
Operating Activities
Net income (loss)	$	7,022		$	(149,935	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Impairment of gas and oil properties		57,869			282,775
Net change in realized and unrealized derivative (gains) losses		(1,995	)		4,887
Depreciation, depletion and amortization		16,524			21,762
Deferred income taxes		(11,663	)		(110,862	)
Other adjustments		355			28
Changes in:
Accounts receivable		(4,188	)		555
Affiliated accounts receivable and payable		(47,009	)		(11,779	)
Inventories		(185	)		(51	)
Prepayments		6,599			17,401
Accounts payable		(3,495	)		6,389
Accrued interest, payroll and taxes		13,011			(10,609	)
Other operating assets and liabilities		(515	)		(382	)
Net cash provided by operating activities		32,330			50,179
Investing Activities
Oil and natural gas property and other expenditures		(23,987	)		(42,870	)
Proceeds from sale of gas and oil properties		—			6,846
Net cash used in investing activities		(23,987	)		(36,024	)
Financing Activities
Issuance (repayment) of affiliated current borrowings, net		(1,928	)		14,713
Repayment of affiliated notes payable		(30	)		(73	)
Common dividend payments		(6,212	)		(14,662	)
Capital contribution (distribution)		826			(7,071	)
Other		(474	)		(13	)
Net cash used in financing activities		(7,818	)		(7,106	)
Increase in cash and cash equivalents		525			7,049
Cash and cash equivalents at beginning of period		36			3
Cash and cash equivalents at end of period	$	561		$	7,052
Significant noncash investing and financing activities:
Accrued capital expenditures	$	4,455		$	11,530
Conversion of short-term and long-term borrowings, advances and payables to equity		—			94,578

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

6

Notes to Combined Financial Statements

(Unaudited)

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). Together, the wholly-owned subsidiaries and DTI-E&P are referred to as the “Companies”, “Dominion E&P”, “we”, “our” or “us”.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, our accompanying unaudited Combined Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited combined financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Combined Financial Statements should be read in conjunction with the Combined Financial Statements and Notes for the year ended December 31, 2009.

In our opinion, the accompanying unaudited Combined Financial Statements contain all adjustments necessary to present fairly our financial position as of March 31, 2010 and our results of operations and cash flows for the three months ended March 31, 2010 and 2009. Such adjustments are normal and recurring in nature unless otherwise noted.

Our combined financial statements include, after eliminating intercompany transactions and balances, the accounts of our respective wholly-owned subsidiaries and of DTI-E&P.

We make certain estimates and assumptions in preparing our combined 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.

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 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.

Note 3. Dispositions

In March 2010, Dominion entered into an agreement to sell substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL Energy for approximately $3.5 billion, subject to customary adjustments. The transaction includes the rights to approximately 491,000 acres in the Marcellus Shale formation. We are retaining certain oil and natural gas wells located on or near our natural gas storage fields. The transaction is expected to close by April 30, 2010, and result in after-tax proceeds of approximately $2.3 billion.

In March 2009, we sold certain oil and gas leases to unrelated third parties covering 2,686 acres in Bradford County, Pennsylvania for $7 million in cash.

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Note 4. Operating Revenue

Our operating revenue consists of the following:

Three Months Ended March 31,	2010		2009
(thousands)
Gas sales	$	125,745	$	84,227
Natural gas liquids sales		3,550		2,841
Oil and condensate sales		2,016		793
Other		512		138
Total operating revenue	$	131,823	$	87,999

Note 5. Income Taxes

For continuing operations, 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:

Three Months Ended March 31,	2010			2009
(thousands)
Income (loss) before income taxes	$	22,193		$	(248,775	)
Total income taxes at U.S. statutory rate (35%)	$	7,768		$	(87,071	)
Increases (reductions) resulting from:
State taxes, net of federal benefit		6,378			(11,762	)
Legislative changes		1,179			—
Other, net		(154	)		(7	)
Income taxes (benefit)	$	15,171		$	(98,840	)

Dominion E&P’s effective tax rate in 2010 reflects the following:

• An increase in net state deferred tax liabilities to reflect the impact of the pending sale of Dominion E&P on state tax rates (subject to phase-in) applicable to such deferred taxes due to the change in timing for which such deferred taxes are now expected to reverse, impacting taxes payable.

• A reduction of deferred tax assets resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010 which eliminated the employer’s deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy.

As of March 31, 2010, Dominion has resolved all adjustments proposed by the Internal Revenue Service (IRS) in its examination of tax years 2002 and 2003 for which a protest was submitted to the Appellate Division of the IRS. Dominion’s settlement with IRS Appeals is expected to be submitted for review by the U.S. Congressional Joint Committee on Taxation in the second or third quarter of 2010. The IRS began its audit of Dominion’s consolidated returns for tax years 2006 and 2007 in April of 2010.

There were no material changes in Dominion E&P’s unrecognized tax benefits during the three months ended March 31, 2010 and 2009. See Note 6 to Dominion E&P’s Combined Financial Statements and Notes for the year ended December 31, 2009 for a discussion of unrecognized tax benefits.

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 the next twelve months.

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Note 6. Comprehensive Income

The following table presents total comprehensive income:

Three months ended March 31,	2010			2009
(thousands)
Net income (loss)	$	7,022		$	(149,935	)
Other comprehensive income (loss):
Net other comprehensive income (loss) associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		(24,656	)		25,334
Total comprehensive loss	$	(17,634	)	$	(124,601	)

Note 7. Fair Value Measurements

Our fair value measurements are made in accordance with the policies discussed in Note 7 to our Combined Financial Statements for the year ended December 31, 2009. In addition, see Note 8 in this report for further information about our derivatives and hedge accounting activities.

Fair values are based on inputs and 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. The inputs and assumptions include the following:

For commodity derivative contracts:

• Forward commodity prices

• Price volatility

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and Dominion

• Credit enhancements

• Time value

We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, including various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models. Because the activity and liquidity of commodity markets varies substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of our over-the-counter derivative contracts is subject to change.

For derivative contracts, we recognize transfers between Levels based on fair value as of the first day of the month in which the transfer occurs.

Nonrecurring Fair Value Measurements

Financial Accounting Standards Board (FASB) fair value measurement guidance became effective for non-financial assets and liabilities on January 1, 2009. As such, the guidance applies to new asset retirement obligations (AROs) incurred after January 1, 2009. During the three months ended March 31, 2010 and 2009, we incurred AROs related to newly drilled wells, which were initially measured at a fair value totaling approximately $0.4 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 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.

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Recurring Fair Value Measurements

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 March 31, 2010
Assets:
Commodity Derivatives	—	$	9,092	—	$	9,092
At December 31, 2009
Assets:
Commodity Derivatives	—	$	48,786	—	$	48,786
Liabilities:
Commodity Derivatives	—	$	208	—	$	208

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:

	2010(1)		2009(1)
(thousands)
Balance at January 1,	$	—	$	1,223
Total realized and unrealized gains:
Included in other comprehensive income (loss)		—		611
Transfers out of Level 3		—		—
Balance at March 31,	$	—	$	1,834

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

For the three months ended March 31, 2010 and 2009, 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 March 31, 2010 and December 31, 2009, 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:

	March 31, 2010				December 31, 2009
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(thousands)
Notes payable to affiliates	$	528,500	$	572,775	$	528,530	$	560,661

(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.

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. Our accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to our Combined Financial Statements and Notes for the year ended December 31, 2009.

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The following table presents the volume of our open derivative positions as of March 31, 2010. 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)	2.4	—

For the three months ended March 31, 2010 and 2009, there were no material amounts recorded for ineffectiveness or excluded from the assessment of effectiveness.

The following table presents selected information related to gains on cash flow hedges included in accumulated other comprehensive income (loss) (AOCI) in our Combined Balance Sheet at March 31, 2010:

	AOCI After-tax		Amounts expected to be  reclassified to earnings during the next 12 months After-tax		Maximum Term
(thousands)
Commodities
Gas	$	4,249	$	4,249	1 month

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.

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 became probable that the forecasted sales of gas would not occur. See Note 9 for further information.

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives and where they are presented on our Combined Balance Sheets:

	Fair Value-Derivatives under  Hedge Accounting		Fair Value-Derivatives not under Hedge Accounting		Total Fair Value
(thousands)
March 31, 2010
Assets
Current Assets
Commodity		—	$	9,092	$	9,092
Total Affiliated Derivative Assets		—		9,092		9,092
December 31, 2009 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
Total Affiliated Derivative Liabilities	$	—	$	208	$	208

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

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The following tables present the gains and losses on our derivatives, as well as where the associated activity is presented on our Combined Balance Sheets and Statements of Income:

Derivatives in cash flow hedging relationships	Amount of Gain Recognized in AOCI  on Derivatives (Effective Portion) (1)		Amount of Gain Reclassified from AOCI into Income
(thousands)
Three Months Ended March 31, 2010
Derivative Type and Location of Gains
Commodity (2)	$	24,526	$	66,050
Three Months Ended March 31, 2009
Derivative Type and Location of Gains
Commodity (2)	$	69,432	$	26,314

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

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

Derivatives not designated as hedging instruments	Amount of Gain  Recognized in Income on Derivatives
(thousands)
Three Months Ended March 31, 2010
Derivative Type and Location of Gains
Commodity (1)	$	3,631
Three Months Ended March 31, 2009
Derivative Type and Location of Gains
Commodity (1)	$	988

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

Note 9. Ceiling Test

We follow the full cost method of accounting for our gas and oil E&P activities, which subjects capitalized costs to a quarterly ceiling test using hedge-adjusted prices. At March 31, 2010, we recorded a ceiling test impairment charge of $58 million ($35 million after-tax) in our Combined Statement of Income primarily due to the discontinuance of hedge accounting for our May 2010 and forward forecasted gas sales. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $66 million ($40 million after-tax). Due to the announced sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, we recognized a gain of $55 million ($33 million after-tax), recorded in operating revenue in our Combined Statement of Income, reflecting the reclassification of gains from AOCI to earnings and subsequent changes in fair value of these contracts in the three months ended March 31, 2010.

In March 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). Decreases in commodity prices, as well as changes in production levels, reserve estimates, future development costs, lifting costs and other factors could result in future ceiling test impairments.

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Note 10. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding the commitments and contingencies disclosed in Note 14 to the Combined Financial Statements and Notes for the year ended December 31, 2009, nor have any significant new matters arisen in the three months ended March 31, 2010.

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 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 March 31, 2010, the remaining liability was approximately $13 million. We do not believe that final resolution of the matter will have a material adverse effect on our results of operations or financial condition.

Workforce Reduction Program

In the first quarter of 2010, Dominion announced a workforce reduction program that is expected to reduce its total workforce by approximately 9% during 2010. The goal of the workforce reduction program is to reduce general and administrative expense growth and further improve the efficiency of the Company. Dominion did not eliminate positions that would compromise safety, reliability or its ability to comply with all laws and regulations. In the first quarter of 2010, we recorded a $5 million ($3 million after-tax) charge primarily reflected in general and administrative expense in our Combined Statement of Income due to severance pay and other benefits related to the workforce reduction program.

Environmental Matters

In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” In April 2010, the EPA and the U. S. Department of Transportation issued final rules that will reduce GHG emissions and improve fuel economy for new cars and trucks sold in the U.S. This rule, when effective, will establish GHG emissions as regulated pollutants under the Clean Air Act. We expect that beginning in 2011, we will be required to obtain permits for GHG emissions from new and modified facilities and amend operating permits for major sources of GHG emissions. Until these actions occur, and the EPA establishes guidance for GHG permitting, including best available control technology, it is not possible to determine the impact on our facilities that emit GHGs.

Note 11. 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 March 31, 2010, no single non-affiliated party represented more than 1% 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 12. 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.

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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. Until the announced sale in March 2010, we had designated the majority of these contracts as cash flow hedges for accounting purposes.

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

	March 31, 2010		December 31, 2009
(thousands)
Derivative assets	$	9,092	$	48,786
Derivative liabilities		—		208

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

Three Months Ended March 31,	2010		2009
(thousands)
Sales to affiliates	$	53,652	$	56,855
Settlements of and unrealized gains on commodity derivative contracts with affiliates		67,685		19,256

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:

Three Months Ended March 31,	2010		2009
(thousands)
Cost of services provided by Dominion Services	$	4,044	$	4,071
Cost of services provided by other affiliates		697		728

See our Combined Financial Statements and Notes for the year ended December 31, 2009 for information regarding our long-term debt, expected maturities, and related principal payments. We incurred interest charges related to affiliates of $9 million in the three months ended March 31, 2010 and 2009, respectively.

At March 31, 2010, our Combined Balance Sheet included a $20 million net liability for federal income taxes payable to Dominion as well as a $14 million liability for state income taxes payable to Dominion. Our Combined Balance Sheet at December 31, 2009, included a $3 million receivable from Dominion for refundable federal income taxes and a $10 million liability for state income taxes payable to Dominion.

Note 13. Subsequent Events

We have evaluated subsequent events through April 28, 2010, which is the date the financial statements were available to be issued.

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