8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): September 21, 2010

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware	001-14901	51-0337383
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

CNX Center

1000 CONSOL Energy Drive

Canonsburg, Pennsylvania 15317

(Address of principal executive offices)

(Zip code)

Registrant’s telephone number, including area code:

(724) 485-4000

Not applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

In the quarter ended June 30, 2010, CONSOL Energy management changed the way segments of the company were being evaluated. These changes coincided with the acquisition of the Dominion Appalachian E&P business and the emerging high volatile metallurgical coal markets that began to develop in 2010. Although the overall segments remain unchanged (coal and gas), certain components of each these segments are now evaluated differently than was previously reported.

Coal is now evaluated as steam coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. This aggregation of reportable segments reflects more closely common financial parameters which are evaluated by executive management, primarily being market usage of coal sold.

Gas is now evaluated as coalbed methane, conventional, Marcellus and other gas. This change was primarily driven by the Dominion Appalachian E&P business and the additional focus on Marcellus Shale activities.

The Quarterly Report on Form 10-Q for the period ending March 31, 2010 has been recast to present the current segment information. Management discussion and analysis has also been recast for the March 31, 2010 Form 10-Q to present financial analysis based on the revised segments in the relevant financial statements. No changes in financial results, financial position or cash flows have been made. Changes are limited to reclassification of financial information into the current segment presentation.

Even though those financial statements related to periods prior to the revised segment reporting, we are providing the revised information in accordance with Securities and Exchange Commission guidance to enable us to incorporate by reference those financial statements and other information into subsequent registration statements that we may file with the SEC under the Securities Act of 1933.

The revised item 1 of Part I (Financial Statements) and item 2 of Part I (Management’s Discussion and Analysis of Financial Condition and Results of Operations) for the quarters ended March 31, 2009 and March 31, 2010 are attached to this current report on Form 8-K as Exhibit 99.2 and incorporated by reference into this Item 8.01. The revised sections of our 2010 First Quarter Form 10-Q included in this report have not been otherwise updated for events occurring after the date of our unaudited Condensed Financial Statements included in our 2010 First Quarter Form 10-Q filed on May 4, 2010. Exhibit 99.2 should be read in conjunction with our 2010 First Quarter Form 10-Q (except for Item 1 of Part I and Item 2 of Part I, which are contained in this report).

Also attached to this current report on Form 8-K as Exhibit 99.3 are the combined financial statements for the quarterly period ended March 31, 2010 of Dominion Exploration & Production Inc., Dominion Reserves, Inc. and Dominion Transmission Inc.

We are also filing a Form 8-K which recasts the segment information in the Annual Report for the year ended December 31, 2009.

Item 9.01 Financial Statements and Exhibits.

99.2	Revised Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations for the quarters ended March 31, 2010 and March 31, 2009 (Part I - Item 1 and Part I - Item 2 of the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31, 2010 and 2009, originally filed with the SEC on May 4, 2010).
99.3	Combined Financial Statements for the quarterly period ended March 31, 2010 of Dominion Exploration & Production Inc., Dominion Reserves, Inc. and Dominion Transmission Inc.
101	Interactive Data File (Form 10-Q for the quarterly period ended March 31, 2010 furnished in XBRL).

SIGNATURES

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

CONSOL ENERGY INC.
By:	/s/    WILLIAM J. LYONS
	William J. Lyons
	Chief Financial Officer and Executive Vice President

Dated: September 21, 2010

Exhibit Index

99.2	Revised Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations for the quarters ended March 31, 2010 and March 31, 2009 (Part I - Item 1 and Part I - Item 2 of the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31, 2010 and 2009, originally filed with the SEC on May 4, 2010).
99.3	Combined Financial Statements for the quarterly period ended March 31, 2010 of Dominion Exploration & Production Inc., Dominion Reserves, Inc. and Dominion Transmission Inc.
101	Interactive Data File (Form 10-Q for the quarterly period ended March 31, 2010 furnished in XBRL).

EX-99.2

Exhibit 99.2

FORM 10-Q ITEM 1. CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(Dollars in thousands, except per share data)

	Three Months Ended March 31,
	2010			2009
Sales—Outside	$	1,169,514		$	1,150,244
Sales—Purchased Gas		3,016			1,465
Sales—Gas Royalty Interests		14,339			12,632
Freight—Outside		31,200			30,916
Other Income		21,991			23,494
Total Revenue and Other Income		1,240,060			1,218,751
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		766,862			667,622
Purchased Gas Costs		2,308			1,530
Acquisition and Financing Fees		46,563			—
Gas Royalty Interests Costs		12,197			10,591
Freight Expense		31,200			30,916
Selling, General and Administrative Expenses		30,130			30,816
Depreciation, Depletion and Amortization		119,186			106,219
Interest Expense		8,145			8,512
Taxes Other Than Income		81,301			77,839
Total Costs		1,097,892			934,045
Earnings Before Income Taxes		142,168			284,706
Income Taxes		34,286			79,735
Net Income		107,882			204,971
Less: Net Income Attributable to Noncontrolling Interest		(7,613	)		(9,152	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	100,269		$	195,819
Earnings Per Share:
Basic	$	0.55		$	1.08
Dilutive	$	0.54		$	1.08
Weighted Average Number of Common Shares Outstanding:
Basic		181,726,480			180,576,479
Dilutive		184,348,982			182,150,090
Dividends Paid Per Share	$	0.10		$	0.10

The accompanying notes are an integral part of these financial statements.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

	(Unaudited) March  31, 2010		December  31, 2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	1,879,007	$	65,607
Accounts and Notes Receivable:
Trade		473,356		317,460
Other Receivables		13,141		15,983
Accounts Receivable—Securitized		50,000		50,000
Inventories		327,443		307,597
Deferred Income Taxes		63,900		73,383
Prepaid Expenses		185,901		161,006
Total Current Assets		2,992,748		991,036
Property, Plant and Equipment:
Property, Plant and Equipment		10,744,244		10,681,955
Less—Accumulated Depreciation, Depletion and Amortization		4,535,190		4,557,665
Total Property, Plant and Equipment—Net		6,209,054		6,124,290
Other Assets:
Deferred Income Taxes		408,361		425,297
Investment in Affiliates		87,856		83,533
Other		176,545		151,245
Total Other Assets		672,762		660,075
TOTAL ASSETS	$	9,874,564	$	7,775,401

The accompanying notes are an integral part of these financial statements.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

	(Unaudited) March  31, 2010			December 31, 2009
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	305,310		$	269,560
Short-Term Notes Payable		566,150			472,850
Borrowings Under Securitization Facility		50,000			50,000
Current Portion of Long-Term Debt		45,690			45,394
Accrued Income Taxes		42,082			27,944
Other Accrued Liabilities		609,525			612,838
Total Current Liabilities		1,618,757			1,478,586
Long-Term Debt:
Long-Term Debt		362,248			363,729
Capital Lease Obligations		58,340			59,179
Total Long-Term Debt		420,588			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		2,684,827			2,679,346
Pneumoconiosis Benefits		186,310			184,965
Mine Closing		388,597			397,320
Gas Well Closing		81,180			85,992
Workers’ Compensation		154,613			152,486
Salary Retirement		176,953			189,697
Reclamation		46,063			27,105
Other		129,772			132,517
Total Deferred Credits and Other Liabilities		3,848,315			3,849,428
TOTAL LIABILITIES		5,887,660			5,750,922
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 225,664,677 Outstanding at March 31, 2010; 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009		2,273			1,830
Capital in Excess of Par Value		2,874,894			1,033,616
Preferred Stock, 15,000,000 authorized, None issued and outstanding		—			—
Retained Earnings		1,525,007			1,456,898
Accumulated Other Comprehensive Loss		(609,537	)		(640,504	)
Common Stock in Treasury, at Cost—1,624,749 Shares at March 31, 2010 and 1,928,159 Shares at December 31, 2009		(58,055	)		(66,292	)
Total CONSOL Energy Inc. Stockholders’ Equity		3,734,582			1,785,548
Noncontrolling Interest		252,322			238,931
TOTAL EQUITY		3,986,904			2,024,479
TOTAL LIABILITIES AND EQUITY	$	9,874,564		$	7,775,401

The accompanying notes are an integral part of these financial statements.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)

	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2009	$	1,830	$	1,033,616	$	1,456,898		$	(640,504	)	$	(66,292	)	$	1,785,548		$	238,931		$	2,024,479
(Unaudited)
Net Income		—		—		100,269			—			—			100,269			7,613			107,882
Treasury Rate Lock (Net of $12 Tax)		—		—		—			(23	)		—			(23	)		—			(23	)
Gas Cash Flow Hedge (Net of $20,218 Tax)		—		—		—			26,199			—			26,199			5,252			31,451
Actuarially Determined Long-Term Liability Adjustments (Net of $2,987 Tax)		—		—		—			4,791			—			4,791			2			4,793
Comprehensive Income (Loss)		—		—		100,269			30,967			—			131,236			12,867			144,103
Issuance of Treasury Stock		—		—		(14,044	)		—			8,237			(5,807	)		—			(5,807	)
Issuance of CONSOL Energy Stock		443		1,828,419		—			—			—			1,828,862			—			1,828,862
Issuance of CNX Gas Stock		—		—		—			—			—			—			139			139
Tax Benefit From Stock-Based Compensation		—		2,962		—			—			—			2,962			—			2,962
Amortization of Stock-Based Compensation Awards		—		8,626		—			—			—			8,626			1,323			9,949
Stock-Based Compensation Awards to CNX Gas Employees		—		1,271		—			—			—			1,271			(1,059	)		212
Net Change in Crown Drilling Noncontrolling Interest		—		—		—			—			—			—			121			121
Dividends ($0.10 per share)		—		—		(18,116	)		—			—			(18,116	)		—			(18,116	)
Balance at March 31, 2010	$	2,273	$	2,874,894	$	1,525,007		$	(609,537	)	$	(58,055	)	$	3,734,582		$	252,322		$	3,986,904

The accompanying notes are an integral part of these financial statements.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended March 31,
	2010			2009
Cash Flows from Operating Activities:
Net Income	$	107,882		$	204,971
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		119,186			106,219
Stock-Based Compensation		9,949			9,906
Loss (Gain) on Sale of Assets		1,439			(1,871	)
Amortization of Mineral Leases		2,190			1,671
Deferred Income Taxes		3,225			16,452
Equity in Earnings of Affiliates		(3,873	)		(3,361	)
Changes in Operating Assets:
Accounts and Notes Receivable		(152,796	)		(30,459	)
Inventories		(22,501	)		(49,866	)
Prepaid Expenses		782			2,320
Changes in Other Assets		8,788			5,327
Changes in Operating Liabilities:
Accounts Payable		45,225			(43,690	)
Other Operating Liabilities		24,092			26,250
Changes in Other Liabilities		14,527			2,938
Other		15,995			2,973
Net Cash Provided by Operating Activities		174,110			249,780
Cash Flows from Investing Activities:
Capital Expenditures		(265,344	)		(299,560	)
Proceeds from Sale of Assets		152			43,827
Net Investment in Equity Affiliates		(450	)		720
Net Cash Used in Investing Activities		(265,642	)		(255,013	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Debt		93,300			(37,300	)
Payments on Miscellaneous Borrowings		(3,487	)		(6,425	)
Tax Benefit from Stock-Based Compensation		3,138			140
Dividends Paid		(18,116	)		(18,060	)
Proceeds from Issuance of Common Stock		1,828,862			—
Issuance of Treasury Stock		1,235			121
Noncontrolling Interest Member Distribution		—			(200	)
Net Cash Provided By (Used In) Financing Activities		1,904,932			(61,724	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,813,400			(66,957	)
Cash and Cash Equivalents at Beginning of Period		65,607			138,512
Cash and Cash Equivalents at End of Period	$	1,879,007		$	71,555

The accompanying notes are an integral part of these financial statements.

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2009 has been derived from the audited consolidated financial statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the consolidated financial statements and related notes for the year ended December 31, 2009 included in CONSOL Energy’s Form 10-K.

As required by the Transfers and Servicing Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, effective January 1, 2010, CONSOL Energy modified the reporting of the Accounts Receivable securitization facility transactions in the Consolidated Financial Statements. The modification includes reporting the pledge of collateral as Accounts Receivable – Securitized and the borrowings are now classified as debt in Borrowings under Securitization Facility. Additionally, similar reclassifications of prior period data have been made to conform to the three months ended March 31, 2010 classifications required by the Transfers and Servicing Topic of the FASB Accounting Standards Codification.

On March 31, 2010, CONSOL Energy issued 44,275,000 shares of common stock, which generated net proceeds of $1,828,862 to fund, in part, the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). The acquisition transaction closed on April 30, 2010. For additional details see “Note 17—Subsequent Events” for additional details.

Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the effect of potential dilutive common shares outstanding during the period. The number of additional shares is calculated by assuming that restricted stock units and performance share units were converted, and outstanding stock options were exercised and that the proceeds from such activity were used to acquire shares of common stock at the average market price during the reporting period. The table below sets forth the outstanding options, unvested restricted stock units, and unvested performance stock units that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:

	For the Three Months Ended March 31,
	2010	2009
Anti-Dilutive Options	821,212	2,404,604
Anti-Dilutive Restricted Stock Units	—	284
Anti-Dilutive Performance Stock Units	6,225	106,540
	827,437	2,511,428

Options exercised during the three months ended March 31, 2010 and 2009 were 59,980 shares and 18,674 shares, respectively. The weighted average exercise price per share of the options exercised during the three months ended March 31, 2010 and 2009 was $20.60 and $8.12, respectively. Additionally, during the three months ended March 31, 2010, and 2009, respectively, 345,722 and 56,004 fully vested restricted stock awards were released.

The computations for basic and dilutive earnings per share from continuing operations are as follows:

	Three Months Ended March 31,
	2010		2009
Net income attributable to CONSOL Energy Inc. shareholders	$	100,269	$	195,819
Average shares of common stock outstanding:
Basic		181,726,480		180,576,479
Effect of stock-based compensation awards		2,622,502		1,573,611
Dilutive		184,348,982		182,150,090
Earnings per share:
Basic	$	0.55	$	1.08
Dilutive	$	0.54	$	1.08

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In March 2010, CONSOL Energy completed the sale of Jones Fork Mining Complex as part of a litigation settlement with Kentucky Fuel Corporation. No cash proceeds were received and $11,585 of litigation settlement expense was recorded in Cost of Goods Sold and Other Operating Charges. The loss recorded was net of $8,700 related to the fair value of estimated amounts to be collected related to an override royalty on future mineable and merchantable coal extracted and sold from the property.

NOTE 3—COMPONENTS OF PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS NET PERIODIC BENEFIT COSTS:

Components of net periodic costs for the three months ended March 31 are as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2010			2009			2010			2009
Service cost	$	3,477		$	2,867		$	3,732		$	3,378
Interest cost		9,228			8,659			40,492			39,735
Expected return on plan assets		(9,318	)		(9,070	)		—			—
Amortization of prior service (credits)		(184	)		(277	)		(11,603	)		(11,604	)
Recognized net actuarial loss		7,865			5,440			17,398			14,970
Net periodic benefit cost	$	11,068		$	7,619		$	50,019		$	46,479

For the three months ended March 31, 2010, $15,928 in contributions were paid to the pension trust and various pension benefits from operating cash flows. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $63,600 to our pension trust in 2010.

CONSOL Energy does not expect to contribute to the other postemployment benefit plan in 2010. We intend to pay benefit claims as they become due. For the three months ended March 31, 2010, $36,019 of other post-employment benefits have been paid.

NOTE 4—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:

Components of net periodic costs for the three months ended March 31 are as follows:

	CWP						Workers’ Compensation
	Three Months Ended March 31,						Three Months Ended March 31,
	2010			2009			2010			2009
Service cost	$	1,946		$	1,769		$	6,754		$	7,099
Interest cost		2,747			3,014			2,289			2,191
Amortization of actuarial gain		(4,981	)		(5,080	)		(768	)		(1,050	)
State administrative fees and insurance bond premiums		—			—			2,419			1,759
Legal and administrative costs		750			675			784			850
Net periodic cost	$	462		$	378		$	11,478		$	10,849

CONSOL Energy does not expect to contribute to the CWP plan in 2010. We intend to pay benefit claims as they become due. For the three months ended March 31, 2010, $3,412 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2010. We intend to pay benefit claims as they become due. For the three months ended March 31, 2010, $9,896 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

The following is a reconciliation, stated in dollars and as a percentage of pretax income, of the U.S. statutory federal income tax rate to CONSOL Energy’s effective tax rate:

	For the Three Months Ended March 31,
	2010					2009
	Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	49,759		35.0	%	$	99,647		35.0	%
Excess tax depletion		(15,169	)	(10.7	)		(27,816	)	(9.8	)
Effect of Domestic Production Activities Deduction		(2,502	)	(1.8	)		(4,328	)	(1.5	)
Net effect of state income taxes		5,616		4.0			10,904		3.8
Other		(3,418	)	(2.4	)		1,328		0.5
Income Tax Expense / Effective Rate	$	34,286		24.1	%	$	79,735		28.0	%

The effective rate for the three months ended March 31, 2010 and 2009 was calculated using the annual effective rate projection on recurring earnings and includes tax liabilities related to certain discrete transactions, such as the Canadian tax settlement described below.

CONSOL Energy was advised by the Canadian Revenue Agency and variance provinces that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Canadian tax returns filed for years 1997 through 2003 had been successfully resolved. As a result of the audit settlement, the Company reflected $3,450 as a discrete reduction to income tax expense in the three months ended March 31, 2010. Accordingly, a discrete federal income tax expense of $1,457 was also recognized related to this transaction.

The total amounts of unrecognized tax benefits at March 31, 2010 and 2009 were $56,916 and $60,691, respectively. If these unrecognized tax benefits were recognized, approximately $15,502 and $14,657, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the three months ended March 31, 2010 and 2009.

CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian tax jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2005.

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of March 31, 2010 and 2009, the Company reported an accrued interest liability relating to uncertain tax positions of $9,129 and $9,724, respectively. The accrued interest liability includes $791 and $627 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the three months ended March 31, 2010 and 2009, respectively.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of March 31, 2010 and 2009, CONSOL Energy had no accrued liability for tax penalties.

NOTE 6—INVENTORIES:

Inventory components consist of the following:

	March 31, 2010		December  31, 2009
Coal	$	193,419	$	173,719
Merchandise for resale		43,076		44,842
Supplies		90,948		89,036
Total Inventories	$	327,443	$	307,597

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $15,808 and $13,696 at March 31, 2010 and December 31, 2009, respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive, on a revolving basis, up to $165,000. The facility also allows for the issuance of letters of credit against the $165,000 capacity. At March 31, 2010, there were no letters of credit outstanding against the facility.

CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation, who in turn sells these receivables to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to a short average collection cycle for such receivables, our collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

Effective January 1, 2010, CONSOL Energy modified the reporting of the Accounts Receivable securitization facility transactions in the Consolidated Financial Statements. The modification includes reporting the pledge of collateral as Accounts Receivable—Securitized and the borrowings are now classified as debt in Borrowings under Securitization Facility. Additionally, similar reclassifications of prior period data have been made to conform to the three months ended March 31, 2010 classifications required by the Transfers and Servicing Topic of the FASB Accounting Standards Codification.

The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $452 and $935 for three months ended March 31, 2010 and 2009, respectively. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.

At March 31, 2010 and December 31, 2009, eligible accounts receivable totaled $165,000 and $151,000, with a subordinated retained interest of approximated $115,000 and $101,000, respectively. Accounts Receivable—Securitized and Borrowings under Securitization Facility of $50,000 were recorded on the Consolidated Balance Sheet for the periods ending March 31, 2010 and December 31, 2009. In accordance with the facility agreement, the company is able to receive proceeds based upon the eligible accounts receivable at the previous month end. There was no change in the facility usage in the three months ended March 31, 2010 and 2009.

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:

The components of property, plant and equipment are as follows:

	March 31, 2010		December  31, 2009
Coal & other plant and equipment	$	4,857,502	$	4,874,880
Gas properties and related development		1,704,818		1,649,476
Coal properties and surface lands		1,276,241		1,284,795
Gas gathering equipment		819,660		804,212
Airshafts		621,476		622,068
Mine development		589,390		573,037
Leased coal lands		503,477		504,475
Coal advance mining royalties		369,128		366,312
Gas advance royalties		2,552		2,700
Total property, plant and equipment		10,744,244		10,681,955
Less Accumulated depreciation, depletion and amortization		4,535,190		4,557,665
Total Net Property, Plant and Equipment	$	6,209,054	$	6,124,290

NOTE 9—SHORT-TERM NOTES PAYABLE:

CONSOL Energy has a five-year $1,000,000 senior secured credit facility, which extends through June 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 22.68 to 1.00 at March 31, 2010. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was less than zero at March 31, 2010. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At March 31, 2010, the $1,000,000 facility had $517,000 of borrowings outstanding and $262,323 of letters of credit outstanding, leaving $220,677 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 0.87% as of March 31, 2010.

CONSOL Energy amended the facility in March 2010 to allow for the Dominion Acquisition. The amendment also allowed CONSOL Energy to issue $1,500,000 of 8% senior unsecured notes due in 2017 and $1,250,000 of 8.25% senior unsecured notes due in 2020 to finance a portion of the Dominion Acquisition. See Note 17—Subsequent Events for further information.

CNX Gas has a five-year $200,000 unsecured credit agreement which extends through October 2010. The agreement contains a negative pledge provision, whereby CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.35 to 1.00 at March 31, 2010. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 67.05 to 1.00 at March 31, 2010. At March 31, 2010, the CNX Gas credit agreement had $49,150 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $135,937 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.41% as of March 31, 2010.

NOTE 10—COMMITMENTS AND CONTINGENCIES:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2008, the Pennsylvania Department of Conservation and Natural Resources (Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company’s underground longwall mining activities caused cracks and seepage damage to the Ryerson Park Dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resources damages totaling $58,000. The Court stayed the proceedings in the state court, holding that the Commonwealth should pursue administrative agency review of the claim. Furthermore, the Court found that the Commonwealth could not recover natural resources damages under applicable law. The Commonwealth then filed a subsidence-damage claim with the Pennsylvania Department of Environmental Protection (“DEP”) and DEP reviewed the issue of whether the dam was damaged by subsidence. On February 16, 2010, DEP issued its interim report, concluding that the alleged damage was subsidence related. The Commonwealth and the Company now move into the next phase of the DEP proceeding, which is the damage phase, in which DEP will determine what amount and in what form the compensatory relief should be provided. Following completion of the next procedural phase before the DEP, either party can appeal the result to the Pennsylvania Environmental Hearing Board (“PEHB”), which will consider the case de novo, meaning without regard to the DEP’s decision, as to any finding of causation of damage and/or the amount of damages. Thereafter, either party may appeal the decision of the PEHB to the Pennsylvania Commonwealth Court, and then, as may be allowed, to the Pennsylvania Supreme Court. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims. The Company intends to vigorously defend the case. However, it is reasonably possible that if damages were awarded to the Commonwealth, the result may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Past payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.

The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $55,000. The current estimated cost of the most likely remediation plan for one of the additional areas discovered is approximately $10,000. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was no expense recognized in the three months ended March 31, 2010 related to this matter. There was $2,336 of expense recognized in cost of goods sold for the three months ended March 31, 2009. CONSOL Energy funded $1,209 and $2,000 in the three months ended March 31, 2010 and 2009, respectively, to an independent trust established for this remediation. The remaining liability at March 31, 2010 of $4,707 is reflected in Other Accrued Liabilities.

As of April 30, 2009, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of probable recoveries from settled claims is estimated to be $3,571. Accordingly, an asset has been included in Other Assets for these claims. We cannot predict the ultimate outcome of this Superfund site; however, it is reasonably possible that payments in the future with respect to this lawsuit may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As part of conducting mining activities at the Buchanan Mine, our subsidiary, Consolidation Coal Company (“CCC”), has to remove water from the mine. Several actions have arisen with respect to the removal of naturally accumulating and pumped water from the Buchanan Mine:

Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company (“Yukon”) filed an action on March 22, 2004 against CCC which is presently pending in the Circuit Court of Buchanan County, Virginia (the “Yukon Action”). The action is related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs are seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs have also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. On March 3, 2010, the trial court delivered an opinion granting partial summary judgment in favor of Yukon, holding that CCC had no legal right to dump or store water from its Buchanan mine into other mines where Yukon has coal and gas interests. The decision did not address any damages suffered by plaintiffs. CONSOL Energy believes that this decision is flawed in numerous respects and CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. CCC has filed a motion for reconsideration, and intends to try the case on the issue of damages, and, if appropriate and allowed, appeal the court’s decision on the plaintiffs’ motion for partial summary judgment to the Virginia Supreme Court. Trial is scheduled for June 1, 2010. The Yukon group has recently filed a demand for arbitration (the “2008 Arbitration”) against ICCC which makes similar claims relating to breach of the lease for water deposits and lost coal claims.

CCC obtained a revision to its environmental permit to deposit water from its Buchanan Mine into void spaces of VP3, and to permit the discharge of water into the nearby Levisa River under controlled conditions. Plaintiffs in the Yukon Action along with the Town of Grundy, Virginia, Buchanan County Board of Supervisors, and others have appealed the revision.

We believe that CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. We also believe CCC was properly issued environmental permits to deposit water from the Buchanan Mine into VP3 and to discharge water into the Levisa River. CCC and the other named CONSOL Energy defendants in the Yukon Action deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine, as well as environmental permits issued to CCC. If a temporary or permanent injunction were to be issued against CCC, if the environmental permits were temporarily suspended or revoked, or if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2007 Bluestone Coal Corporation filed a lawsuit against the Company and its subsidiary, CNX Land Resources, in the United States District Court for the Southern District of West Virginia. The suit alleged that the Company breached a contract that allegedly provides Bluestone with an option to lease coal reserves within a seven-and-one-half mile radius of Bishop, WV and sought damages of $1,200,000. The writing relied upon only refers to a right of first refusal, rather than an option. The lawsuit has been settled. The terms of the settlement are confidential, but include CONSOL Energy granting to Bluestone the option to acquire certain mining assets and reserves. In the three months ended March 31, 2010, Bluestone exercised one of its options to acquire the Jones Fork operation in Kentucky, which resulted in a pre-tax loss of $11,585. The remaining settlement terms did not materially impact the financial position, results of operations or cash flows of CONSOL Energy.

South Carolina Electric & Gas Company (“SCE&G”), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 11, 2010. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. However, if damages were awarded to SCE&G, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill and continuing thereafter, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection (“WVDEP”) that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC’s discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. Pursuant to the December 18, 2009 WVDEP Unilateral Order, CCC submitted a plan and schedule to WVDEP which provides for construction of a centralized advanced technology mine water treatment plant by May 31, 2013 to achieve compliance with chloride effluent limits and in-stream chloride water quality standards. The cost of the treatment plant may reach or exceed $100,000. Additionally, CCC is currently negotiating a joint Consent Decree with EPA and the WVDEP that is likely to include the compliance plan and schedule that was submitted to WVDEP. The Consent Decree is also likely to include civil penalties to settle alleged past violations related to chlorides without an admission of liability. The parties have not yet discussed the amount of a civil penalty. The Consent Decree will provide CCC with a schedule for orderly construction of the advanced water treatment plant and related facilities. If we are required to comply with in-stream chloride limits on an accelerated basis or if we enter into a Consent Decree that includes a civil penalty, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

CONSOL Energy has been named as a defendant in five putative class actions brought by alleged shareholders of CNX Gas challenging the proposed tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy does not already own. The cases are: Schurr v. CONSOL Energy and others (No. 2010-2333), filed in the Court of Common Pleas of Washington County, Pennsylvania on March 29, 2010; Gummel v. CONSOL Energy (No. 5377-VCL), filed March 29, 2010 in the Delaware Court of Chancery; Polen v. CONSOL Energy and others (No. 2010-2626), filed in the Court of Common Pleas of Washington County, Pennsylvania on April 12, 2010; Gaines v. CONSOL Energy and others (No. 5378), filed March 30, 2010 in the Delaware Court of Chancery; and Hurwitz v. CONSOL Energy and others (NO. 5405), filed in the Delaware Court of Chancery on April 13, 2010. Other than the Gummel case, the suits also name CNX Gas and certain officers and directors of CONSOL Energy and

CNX Gas as defendants. All five actions generally allege that CONSOL Energy has breached and/or has aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders. Among other things, the actions seek a permanent injunction against or rescission of the proposed tender offer, damages, and attorneys’ fees and expenses. CONSOL Energy believes that these actions are without merit and intends to defend them vigorously. We cannot predict the ultimate outcome of this litigation; however, if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia is expected to increase. Our initial belief is that as a result of the changes in mine plans and because mining in some areas is anticipated to be curtailed earlier than originally anticipated, the quantity of material required to reclaim the operation in its present state will be increased. As of this time, no detailed reclamation plan has been developed and the definitive costs associated with the increased reclamation are not available, however, our initial estimates indicate the reclamation liability could equal or exceed $25,000. As a result, $25,000 of expense was recognized in the three months ended March 31, 2010. Detailed reclamation plans and mining plans are being developed to determine the impacts of these revised plans on the associate reclamation liability. It is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to Fola reclamation may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

On February 14, 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. In April 2010, CNX Gas and GeoMet entered into an agreement involving the exchange of less than 800 acres of coalbed methane rights in Virginia and the grant by Consolidation Coal Company to GeoMet of consent to stimulate the coal seam on certain of GeoMet’s drilling units in Virginia. This litigation was settled as part of that transaction. CNX Gas did not pay any amount to GeoMet in connection with the settlement of this litigation.

On January 7, 2009, CNX Gas received a civil investigative demand for information and documents from the Attorney General of the Commonwealth of Virginia regarding the company’s exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request, the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific allegations against the company. CNX Gas does not believe that it has violated the Virginia Antitrust Act and the company is cooperating with the Attorney General’s investigation.

The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

In April 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ calculation of the license tax on the basis of the wellhead value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, CNX Gas paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, we have continued to pay Buchanan County taxes based on our method of calculating the taxes. This matter was settled on February 2, 2010. Under the terms of the settlement, among other things, CNX Gas agreed to pay an amount to Buchanan County, the present value of which was previously accrued for this matter, and Buchanan County agreed to certain deductions for post-production costs in the calculation of the license tax for periods after January 1, 2010, which will reduce our costs in the future.

At March 31, 2010, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.

	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	192,789	$	128,292	$	64,497	$	—	$	—
Environmental		57,842		35,895		21,947		—		—
Gas		14,913		14,913		—		—		—
Other		11,765		11,601		164		—		—
Total Letters of Credit		277,309		190,701		86,608		—		—
Surety Bonds:
Employee-Related		193,251		174,251		19,000		—		—
Environmental		363,082		349,602		13,480		—		—
Gas		4,456		4,392		64		—		—
Other		9,774		9,761		13		—		—
Total Surety Bonds		570,563		538,006		32,557		—		—
Guarantees:
Coal		87,677		62,029		19,648		1,000		5,000
Gas		53,085		27,448		22,537		—		3,100
Other		266,323		44,100		69,757		44,096		108,370
Total Guarantees		407,085		133,577		111,942		45,096		116,470
Total Commitments	$	1,254,957	$	862,284	$	231,107	$	45,096	$	116,470

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Gas financial guarantees have primarily been provided to support various performance bonds related to land usage and restorative issues. Other guarantees have been provided to support insurance policies, legal matters related to the full and timely payments to lessors of mining equipment, and various other items necessary in the normal course of business.

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheet. As of March 31, 2010, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due	Amount
Less than 1 year	$	59,490
1-3 years		74,887
3-5 years		62,240
More than 5 years		333,337
Total Purchase Obligations	$	529,954

Costs related to major equipment purchases under these purchase obligations were $18,205 and $63,383 for the three months ended March 31, 2010 and 2009, respectively. Firm transportation expense under these purchase obligations was $6,695 and $4,586 for the three months ended March 31, 2010 and 2009, respectively. Expenses related to gas drilling purchase obligations were $605 and $0 for the three months ended March 31, 2010 and 2009, respectively. Expenses related to other operating goods and services under these purchase obligations was $30 and $30 for the three months ended March 31, 2010 and 2009.

NOTE 11—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CONSOL Energy’s natural gas derivative instruments also participate in CONSOL Energy’s revolving credit facility. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy has entered into forward and option contracts on various commodities to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.

As of March 31, 2010, the total notional amount of the Company’s outstanding natural gas forward contracts was 73.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $75,816 of unrealized gain is expected to be reclassified from Other Comprehensive Income into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of March 31, 2010, CONSOL Energy did not have any outstanding coal sales options. For the quarter ended March 31, 2009, CONSOL Energy recognized in Other Income on the Consolidated Statement of Income, a gain of $2,135 for the coal sales options which were not designated as hedging instruments.

The fair value of CONSOL Energy’s derivative instruments at March 31, 2010 is as follows:

	Derivatives As of March 31, 2010
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	124,811
Natural Gas Price Swaps	Other Assets		44,200
Total derivatives designated as hedging instruments		$	169,011

The effect of derivative instruments on the Consolidated Statement of Income for the three months ended March 31, 2010 is as follows:

Derivative in Cash Flow Hedging Relationship	Amount  of Gain Recognized in OCI on Derivative 2010		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2010		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income  on Derivative 2010
Natural Gas Price Swaps	$	74,708	Outside Sales	$	43,399	Outside Sales	$	(142	)
Total	$	74,708		$	43,399		$	(142	)

The fair value of CONSOL Energy’s derivative instruments at December 31, 2009 is as follows:

	Derivatives As of  December 31, 2009
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	99,265
Natural Gas Price Swaps	Other Assets		18,218
Total derivatives designated as hedging instruments		$	117,483

The effect of derivative instruments on the Consolidated Statement of Income for the three months ended March 31, 2009 is as follows:

Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2009		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2009		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income  on Derivative 2009
Natural Gas Price Swaps	$	78,948	Outside Sales	$	50,618	Outside Sales	$	(375	)
Total	$	78,948		$	50,618		$	(375	)

Derivatives not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivative	Amount of Gain Recognized in Income on Derivative 2009
Coal Sales Options	Other Income	$	2,135
Total		$	2,135

NOTE 12—OTHER COMPREHENSIVE LOSS:

Total comprehensive income (loss), net of tax, for the three months ended March 31, 2010 was as follows:

	Treasury Rate Lock			Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Adjustments for Non- controlling Interest			Accumulated Other Comprehensive Loss
Balance at December 31, 2009	$	180		$	71,378		$	(699,434	)	$	(12,628	)	$	(640,504	)
Net increase in value of cash flow hedges		—			74,850			—			(12,500	)		62,350
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(43,399	)		—			7,248			(36,151	)
Current period change		(23	)		—			4,793			(2	)		4,768
Balance at March 31, 2010	$	157		$	102,829		$	(694,641	)	$	(17,882	)	$	(609,537	)

NOTE 13—FAIR VALUES OF FINANCIAL INSTRUMENTS:

The financial instruments measured at fair value on a recurring basis are summarized below:

	Fair Value Measurements at March 31, 2010
Description	Quoted Prices in Active  Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	169,011	$	—

The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.

Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

	March 31, 2010						December 31, 2009
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	1,879,007		$	1,879,007		$	65,607		$	65,607
Short-term notes payable	$	(566,150	)	$	(566,150	)	$	(472,850	)	$	(472,850	)
Borrowings Under Securitization Facility	$	(50,000	)	$	(50,000	)	$	(50,000	)	$	(50,000	)
Long-term debt	$	(401,318	)	$	(419,069	)	$	(402,753	)	$	(420,056	)

Note 14—Segment Information:

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Steam, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three months ended March 31, 2010, the Steam aggregated segment includes the following mines: Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the three months ended March 31, 2010, the Low Volatile Metallurgical aggregated segment includes the Buchanan mine. For the three months ended March 31, 2010, the High Volatile Metallurgical aggregated segment includes: Bailey, Enlow Fork and Emery coal sales. The Other Coal segment includes our purchased coal activities, idled mine cost, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas unit includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus Shale, Conventional and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas segment but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2009 segment information have been made to conform to the 2010 presentation, which includes the addition of the Gas operating segments.

Industry segment results for three months ended March 31, 2010 are:

	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas		Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales - outside	$	716,723	$	126,457	$	57,367	$	23,063		$	923,610	$	161,043	$	7,983	$	2,572	$	1,549		$	173,147	$	72,757	$	—		$	1,169,514
Sales - Purchased Gas		—		—		—		—			—		—		—		—		3,016			3,016		—		—			3,016
Sales - Gas Royalty Interests		—		—		—		—			—		—		—		—		14,339			14,339		—		—			14,339
Freight - outside		—		—		—		31,200			31,200		—		—		—		—			—		—		—			31,200
Intersegment transfers		—		—		—		—			—		—		—		—		866			866		43,604		(44,470	)		—
Total Sales and Freight	$	716,723	$	126,457	$	57,367	$	54,263		$	954,810	$	161,043	$	7,983	$	2,572	$	19,770		$	191,368	$	116,361	$	(44,470	)	$	1,218,069
Earnings (Loss) Before Income Taxes	$	169,034	$	48,586	$	30,255	$	(132,824	)	$	115,051	$	81,027	$	2,082	$	35	$	(9,459	)	$	73,685	$	1,408	$	(47,976	)	$	142,168	(A)
Segment assets										$	4,948,660										$	2,264,026	$	310,551	$	2,351,327		$	9,874,564	(B)
Depreciation, depletion andamortization										$	82,324										$	32,092	$	4,770	$	—		$	119,186
Capital expenditures										$	199,325										$	65,314	$	705	$	—		$	265,344

(A) Includes equity in earnings (loss) of unconsolidated affiliates of $2,430, ($517) and $1,960 for Coal, Gas and All Other, respectively.

(B) Includes investments in unconsolidated equity affiliates of $15,648, $24,074 and $48,134 for Coal, Gas and All Other, respectively.

Industry segment results for three months ended March 31, 2009 are:

	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales - outside	$	835,063	$	69,543	$	—	$	13,630		$	918,236	$	158,218	$	1,595	$	1,645		$	449		$	161,907	$	70,101	$	—		$	1,150,244
Sales - Purchased Gas		—		—		—		—			—		—		—		—			1,465			1,465		—		—			1,465
Sales - Gas Royalty Interests		—		—		—		—			—		—		—		—			12,632			12,632		—		—			12,632
Freight - outside		—		—		—		30,916			30,916		—		—		—			—			—		—		—			30,916
Intersegment transfers		—		—		—		—			—		—		—		—			435			435		37,519		(37,954	)		—
Total Sales and Freight	$	835,063	$	69,543	$	—	$	44,546		$	949,152	$	158,218	$	1,595	$	1,645		$	14,981		$	176,439	$	107,620	$	(37,954	)	$	1,195,257
Earnings (Loss) Before Income Taxes	$	267,308	$	23,411	$	—	$	(92,073	)	$	198,646	$	89,966	$	444	$	(262	)	$	(718	)	$	89,430	$	7,946	$	(11,316	)	$	284,706	(C)
Segment assets										$	4,603,165											$	2,203,067	$	334,027	$	432,028		$	7,572,287	(D)
Depreciation, depletion and amortization										$	78,205											$	22,819	$	5,195	$	—		$	106,219
Capital expenditures										$	160,935											$	133,550	$	5,075	$	—		$	299,560

(C) Includes equity in earnings (loss) of unconsolidated affiliates of $1,428, $262 and $1,671 for Coal, Gas and All Other, respectively.

(D) Includes investments in unconsolidated equity affiliates of $10,093, $25,466 and $40,078 for Coal, Gas and All Other, respectively. Also, included in the Coal segment is $59,354 of receivables related to the Emergency Economic Stabilization Act of 2008.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:

	For the Three Months Ended March 31,
	2010			2009
Segment Earnings Before Income Taxes for total reportable business segments	$	188,736		$	288,076
Segment Earnings Before Income Taxes for all other businesses		1,408			7,946
Interest income (expense), net and other non-operating activity (E)		(1,541	)		(8,432	)
Acquisition and Financing Fees (E)		(46,563	)		—
Operating lease cease-use		128			—
Corporate Restructuring (E)		—			(2,884	)
Earnings Before Income Taxes	$	142,168		$	284,706

Total Assets:

	March 31,
	2010		2009
Segment assets for total reportable business segments	$	7,212,686	$	6,806,232
Segment assets for all other businesses		310,551		334,027
Items excluded from segment assets:
Cash and other investments (E)		1,878,464		71,680
Deferred tax assets		472,261		359,401
Bond issuance costs		602		947
Total Consolidated Assets	$	9,874,564	$	7,572,287

(E) Excludes amounts specifically related to the gas segment.

NOTE 15—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $250,000, 7.875% per annum notes due March 1, 2012 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, an 83.3% owned guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. CNX Gas is presented in a separate column in accordance with SEC Regulation S-X Rule 3-10. CNX Gas Corporation is a reporting company under Section 12(b) of the Securities Exchange Act of 1933, and as such, CNX Gas Corporation files its own financial statements with the Securities and Exchange Commission and those financial statements, when filed, are publicly available on Edgar. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the three months ended March 31, 2010:

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	174,013	$	946,077		$	50,456	$	(1,032	)	$	1,169,514
Sales—Purchased Gas		—			3,016		—			—		—			3,016
Sales—Gas Royalty Interests		—			14,339		—			—		—			14,339
Freight—Outside		—			—		31,200			—		—			31,200
Other Income (including equity earnings)		193,898			896		8,035			6,308		(187,146	)		21,991
Total Revenue and Other Income		193,898			192,264		985,312			56,764		(188,178	)		1,240,060
Cost of Goods Sold and Other Operating Charges		19,608			41,979		636,152			3,407		65,716			766,862
Purchased Gas Costs		—			2,308		—			—		—			2,308
Acquisition and Financing Fees		46,563			—		—			—		—			46,563
Gas Royalty Interests Costs		—			12,214		—			—		(17	)		12,197
Related Party Activity		(1,983	)		—		(1,982	)		44,517		(40,552	)		—
Freight Expense		—			—		31,200			—		—			31,200
Selling, General and Administrative Expense		—			23,575		28,095			287		(21,827	)		30,130
Depreciation, Depletion and Amortization		3,404			32,092		83,011			679		—			119,186
Interest Expense		3,750			1,915		2,566			5		(91	)		8,145
Taxes Other Than Income		2,539			4,781		73,214			767		—			81,301
Total Costs		73,881			118,864		852,256			49,662		3,229			1,097,892
Earnings (Loss) Before Income Taxes		120,017			73,400		133,056			7,102		(191,407	)		142,168
Income Tax Expense (Benefit)		(26,816	)		27,967		30,795			2,340		—			34,286
Net Income		146,833			45,433		102,261			4,762		(191,407	)		107,882
Less: Net Income Attributable to Noncontrolling Interest		—			194		(194	)		—		(7,613	)		(7,613	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	146,833		$	45,627	$	102,067		$	4,762	$	(199,020	)	$	100,269

Balance Sheet at March 31, 2010:

	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	1,844,382		$	1,093		$	32,084		$	1,448		$	—		$	1,879,007
Accounts and Notes Receivable:
Trade		—			46,749			37			426,570			—			473,356
Securitized		50,000			—			—			—			—			50,000
Other		1,921			579			5,265			5,376			—			13,141
Inventories		1			—			284,366			43,076			—			327,443
Deferred Income Taxes		108,795			(44,895	)		—			—			—			63,900
Prepaid Expenses		21,127			129,355			33,778			1,641			—			185,901
Total Current Assets		2,026,226			132,881			355,530			478,111			—			2,992,748
Property, Plant and Equipment:
Property, Plant and Equipment		160,759			2,480,394			8,077,949			25,142			—			10,744,244
Less-Accumulated Depreciation, Depletion and Amortization		86,198			466,390			3,965,725			16,877			—			4,535,190
Property, Plant and Equipment-Net		74,561			2,014,004			4,112,224			8,265			—			6,209,054
Other Assets:
Deferred Income Taxes		764,897			(356,536	)		—			—			—			408,361
Investment in Affiliates		4,614,662			24,074			708,118			4,838			(5,263,836	)		87,856
Other		74,723			48,131			42,280			11,411			—			176,545
Total Other Assets		5,454,282			(284,331	)		750,398			16,249			(5,263,836	)		672,762
Total Assets	$	7,555,069		$	1,862,554		$	5,218,152		$	502,625		$	(5,263,836	)	$	9,874,564
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	99,750		$	63,724		$	124,966		$	16,870		$	—		$	305,310
Accounts Payable (Recoverable)- Related Parties		1,914,489			2,725			(2,306,002	)		388,788			—			—
Short-Term Notes Payable		517,000			49,150			—			—			—			566,150
Current Portion Long-Term Debt		552			8,756			35,923			459			—			45,690
Accrued Income Taxes		42,082			20,157			(20,157	)		—			—			42,082
Borrowings under Securitization Facility		50,000			—			—			—			—			50,000
Other Accrued Liabilities		687,957			24,159			(110,308	)		7,717			—			609,525
Total Current Liabilities		3,311,830			168,671			(2,275,578	)		413,834			—			1,618,757
Long-Term Debt:		250,322			63,609			106,003			654			—			420,588
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—			3,699			2,681,128			—			—			2,684,827
Pneumoconiosis		—			—			186,310			—			—			186,310
Mine Closing		—			—			388,597			—			—			388,597
Gas Well Closing		—			8,341			72,839			—			—			81,180
Workers’ Compensation		—			—			154,602			11			—			154,613
Salary Retirement		176,959			—			—			(6	)		—			176,953
Reclamation		(3,412	)		—			49,475			—			—			46,063
Other		85,705			31,958			12,104			5			—			129,772
Total Deferred Credits and Other Liabilities		259,252			43,998			3,545,055			10			—			3,848,315
Total Consol Energy Inc. Stockholders’ Equity		3,733,665			1,590,525			3,838,423			88,127			(5,516,158	)		3,734,582
Noncontrolling Interest		—			(4,249	)		4,249			—			252,322			252,322
Total Liabilities and Stockholders’ Equity	$	7,555,069		$	1,862,554		$	5,218,152		$	502,625		$	(5,263,836	)	$	9,874,564

Income Statement for the three months ended March 31, 2009:

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	162,340	$	938,424		$	50,480	$	(1,000	)	$	1,150,244
Sales—Purchased Gas		—			1,465		—			—		—			1,465
Sales—Gas Royalty Interests		—			12,632		—			—		—			12,632
Freight—Outside		—			—		30,916			—		—			30,916
Other Income (including equity earnings)		214,359			1,947		12,744			5,962		(211,518	)		23,494
Total Revenue and Other Income		214,359			178,384		982,084			56,442		(212,518	)		1,218,751
Cost of Goods Sold and Other Operating Charges		18,496			33,675		529,734			47,842		37,875			667,622
Purchased Gas Costs		—			1,530		—			—		—			1,530
Gas Royalty Interests Costs		—			10,601		—			—		(10	)		10,591
Related Party Activity		547			—		28,158			428		(29,133	)		—
Freight Expense		—			—		30,916			—		—			30,916
Selling, General and Administrative Expense		—			16,188		14,303			325		—			30,816
Depreciation, Depletion and Amortization		3,343			22,819		81,250			661		(1,854	)		106,219
Interest Expense		3,825			1,957		2,812			4		(86	)		8,512
Taxes Other Than Income		1,880			2,533		72,777			649		—			77,839
Total Costs		28,091			89,303		759,950			49,909		6,792			934,045
Earnings (Loss) Before Income Taxes		186,268			89,081		222,134			6,533		(219,310	)		284,706
Income Tax Expense (Benefit)		(9,551	)		34,440		52,374			2,472		—			79,735
Net Income		195,819			54,641		169,760			4,061		(219,310	)		204,971
Less: Net Income Attributable to Noncontrolling Interest		—			263		(263	)		—		(9,152	)		(9,152	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	195,819		$	54,904	$	169,497		$	4,061	$	(228,462	)	$	195,819

Balance Sheet at December 31, 2009:

	Parent Issuer		CNX Gas Guarantor			Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	59,549	$	1,124		$	3,764		$	1,170	$	—		$	65,607
Accounts and Notes Receivable:
Trade		—		43,421			113			273,926		—			317,460
Securitized		50,000		—			—			—		—			50,000
Other		4,781		975			3,281			6,946		—			15,983
Inventories		—		—			262,755			44,842		—			307,597
Deferred Income Taxes		108,254		(34,871	)		—			—		—			73,383
Prepaid Expenses		18,979		103,094			36,767			2,166		—			161,006
Total Current Assets		241,563		113,743			306,680			329,050		—			991,036
Property, Plant and Equipment:
Property, Plant and Equipment		162,145		2,409,751			8,082,159			27,900		—			10,681,955
Less-Accumulated Depreciation, Depletion and Amortization		82,733		433,201			4,022,295			19,436		—			4,557,665
Property, Plant and Equipment-Net		79,412		1,976,550			4,059,864			8,464		—			6,124,290
Other Assets:
Deferred Income Taxes		759,790		(334,493	)		—			—		—			425,297
Investment in Affiliates		4,399,823		24,591			797,269			3,921		(5,142,071	)		83,533
Other		84,736		21,627			33,216			11,666		—			151,245
Total Other Assets		5,244,349		(288,275	)		830,485			15,587		(5,142,071	)		660,075
Total Assets	$	5,565,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,775,401
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	93,876	$	53,516		$	114,872		$	7,296	$	—		$	269,560
Accounts Payable (Recoverable)—Related Parties		2,117,616		5,171			(2,378,119	)		255,332		—			—
Short-Term Notes Payable		415,000		57,850			—			—		—			472,850
Current Portion Long-Term Debt		501		8,616			35,853			424		—			45,394
Accrued Income Taxes		27,944		31,765			(31,765	)		—		—			27,944
Borrowings under Securitization Facility		50,000		—			—			—		—			50,000
Other Accrued Liabilities		546,066		25,455			34,569			6,748		—			612,838
Total Current Liabilities		3,251,003		182,373			(2,224,590	)		269,800		—			1,478,586
Long-Term Debt:		250,255		65,690			106,369			594		—			422,908
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—		3,642			2,675,704			—		—			2,679,346
Pneumoconiosis		—		—			184,965			—		—			184,965
Mine Closing		—		—			397,320			—		—			397,320
Gas Well Closing		—		8,312			77,680			—		—			85,992
Workers’ Compensation		—		—			152,486			—		—			152,486
Salary Retirement		189,697		—			—			—		—			189,697
Reclamation		—		—			27,105			—		—			27,105
Other		88,821		35,101			8,595			—		—			132,517
Total Deferred Credits and Other Liabilities		278,518		47,055			3,523,855			—		—			3,849,428
Total Consol Energy Inc. Stockholders’ Equity		1,785,548		1,511,270			3,787,025			82,707		(5,381,002	)		1,785,548
Noncontrolling Interest		—		(4,370	)		4,370			—		238,931			238,931
Total Liabilities and Stockholders’ Equity	$	5,565,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,775,401

Cash Flow for the Three Months Ended March 31, 2010:

	Parent			CNX Gas			Guarantor			Non-Guarantor			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	(132,146	)	$	75,203		$	230,644		$	409		$	—	$	174,110
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(65,314	)	$	(200,030	)	$	—		$	—	$	(265,344	)
Investment in Equity Affiliates		—			—			(450	)		—			—		(450	)
Other Investing Activities		—			8			144			—			—		152
Net Cash Used in Investing Activities	$	—		$	(65,306	)	$	(200,336	)	$	—		$	—	$	(265,642	)
Cash Flows from Financial Activities:
Dividends Paid	$	(18,116	)	$	—		$	—		$	—		$	—	$	(18,116	)
Proceeds from Short Term Borrowing		102,000			(8,700	)		—			—			—		93,300
Proceeds from the Issuance of Common Stock		1,828,862			—			—			—			—		1,828,862
Other Financing Activities		4,233			(1,228	)		(1,988	)		(131	)		—		886
Net Cash Provided by Financing Activities	$	1,916,979		$	(9,928	)	$	(1,988	)	$	(131	)	$	—	$	1,904,932

Cash Flow for the Three Months Ended March 31, 2009:

	Parent			CNX Gas			Guarantor			Non-Guarantor			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	(2,583	)	$	126,437		$	126,122		$	(196	)	$	—	$	249,780
Cash Flows from Investing Activities:
Capital Expenditures	$	(29	)	$	(133,550	)	$	(165,981	)	$	—		$	—	$	(299,560	)
Investment in Equity Affiliates		—			—			720			—			—		720
Other Investing Activities		—			—			43,827			—			—		43,827
Net Cash Used in Investing Activities	$	(29	)	$	(133,550	)	$	(121,434	)	$	—		$	—	$	(255,013	)
Cash Flows from Financial Activities:
Dividends Paid	$	(18,060	)	$	—		$	—		$	—		$	—	$	(18,060	)
Proceeds from Short Term Borrowing		(45,000	)		7,700			—			—			—		(37,300	)
Other Financing Activities		137			(2,267	)		(4,111	)		(123	)		—		(6,364	)
Net Cash Used in Financing Activities	$	(62,923	)	$	5,433		$	(4,111	)	$	(123	)	$	—	$	(61,724	)

NOTE 16—RECENT ACCOUNTING PRONOUNCEMENTS:

In January 2010, the Financial Accounting Standards Board issued an update to the Fair Value Measurement and Disclosure Topic of the FASB Accounting Standards Codification which is intended to provide additional application guidance and enhance disclosures regarding fair value measurements. This update also provides amendments that require new disclosures regarding transfers between levels of fair value measurements. This guidance did not have an impact on CONSOL Energy.

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for CONSOL beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have a material impact on CONSOL’s financial statements.

NOTE 17—SUBSEQUENT EVENTS:

On April 1, 2010, CONSOL Energy closed the offering of $1,500,000 of 8.00% senior notes which mature on April 1, 2017 and $1,250,000 of 8.25% senior notes which mature on April 1, 2020. Interest on the notes will be payable semi-annually on April 1 and October 1 of each year, commencing on October 1, 2010. The notes are guaranteed by substantially all of our existing and future wholly owned domestic subsidiaries. Net proceeds received related to the issuance of the senior notes were $2,698,273. The proceeds from this offering will be used to finance, in part, the Dominion Acquisition.

On April 23, 2010, CONSOL Energy amended the accounts receivable securitization facility to allow the Company to receive, on a revolving basis, up to $200,000. Previously, the facility provided up to $165,000 of short-term funding or letters of credit. The trade accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. The facility was expanded to meet the future cash needs of the Company.

On April 28, 2010, CONSOL Energy commenced a tender offer to acquire all of the shares of CNX Gas common stock that it does not currently own at a cash price of $38.25 per share. CONSOL Energy currently owns approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. CONSOL Energy’s offer is subject to a number of conditions, including the condition, which cannot be waived, that there is tendered into the offer at least a majority of the outstanding CNX Gas shares not currently held by CONSOL Energy. Following the purchase by CONSOL Energy of shares of CNX Gas in the offer, CONSOL Energy intends to merge CNX Gas into a wholly owned subsidiary of CONSOL Energy, with CNX Gas surviving the merger as a wholly owned subsidiary of CONSOL Energy. As a result of the merger, each outstanding CNX Gas share will be converted into the right to receive $38.25. CONSOL Energy anticipates financing the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and/or proceeds from its recently closed offering of common stock. Previously, on March 21, 2010, CONSOL Energy announced that it had entered into an agreement with T. Rowe Price Associates, Inc., on behalf of its investment advisory clients owning approximately 9.5 million shares of CNX Gas common stock, or approximately 37% of the shares of CNX Gas that CONSOL Energy does not currently own. Under the agreement, CONSOL Energy agreed, subject to certain conditions, to commence this tender offer and T. Rowe Price agreed to tender these shares of CNX Gas common stock subject to the rights of certain clients with respect to those shares which are discretionary account shares.

On April 30, 2010, CONSOL Energy completed the Dominion Acquisition for a cash payment of $3,475,000 which will be principally allocated to oil and gas properties, wells and well related equipment. The acquisition includes approximately 1 Tcfe of net proved reserves and 1.45 million acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings are approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. The acquisition enhances our position as a leading unconventional gas producer and as a leading producer of gas in Appalachia.

We have evaluated all subsequent events through the date the financial statements were issued. No additional material recognized or non-recognized subsequent events were identified.

FORM 10-Q ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $100 million, or $0.54 per diluted share, for the three months ended March 31, 2010. Net income attributable to CONSOL Energy shareholders was $196 million, or $1.08 per diluted share, for the three months ended March 31, 2009. See “Results of Operations” below for a detailed explanation of the variance incurred in the period-to-period comparison.

Strengthening demand, decreasing coke stocks, and ongoing logistical constraints are setting up 2010 to be a very strong year for metallurgical coal. Steel plant capacity utilization rates in the U.S. and globally continues to improve compared to last year. Domestic steel mills are using approximately 73% of their capacity, while Asian steel mills currently are running at full capacity. Chinese steel demand is again driving world demand and pricing for coking coal. Through its agreement with Xcoal, CONSOL expects to increase its sales to Asian mills throughout 2010.

Going into the fourth quarter of 2009, thermal coal inventories were at historic highs. Because of the much colder than normal weather in December 2009 through February 2010, inventories at coal-fired power generators have been significantly drawn down, but are still somewhat higher than normal. Customers in our major market area (the PJM power pool) had an estimated 55-60 days of inventory on hand as of the end of March. CONSOL Energy believes that thermal coal inventories could return to normal by the end of the year. Despite the outlook for a gradual economic recovery, which would strengthen demand, low gas prices in 2010 could result in power generators continuing to burn gas in place of coal, based on dispatch economics. Just as in 2009, the company anticipates that up to 30 million tons of coal generation could be displaced by natural gas generation in 2010. This could offset some of the benefit from production cuts. With the tightening regulatory environment in Central Appalachia, increased economic activity and its low cost position, however, CONSOL Energy is in a position to increase market share in a flat-to-slightly expanding market. CONSOL’s ability to penetrate the Asian high-vol coking coal markets with some of its Northern Appalachian coals is also enabling the company to receive higher prices at its mines, while reducing supply into its traditional thermal markets.

At the close of the winter heating season, natural gas in storage fields was at 1,638 billion cubic feet. This was 160 billion cubic feet above the five-year average, but 16 billion cubic feet below last year’s level. Gas prices have weakened to about the $4.00 per million cubic feet level, as rising rig counts have caused concern that rising production could more than offset rising demand from an economic recovery. CNX Gas will add a second horizontal rig to its Marcellus Shale drilling program on June 1, 2010. CNX Gas, with its low costs and rising production volumes, is expected to outperform its peers during this period of price weakness.

Because of the rapidly changing regulatory environment in which CONSOL Energy operates, several factors may impact the cost of our coal and gas production in the future. The impacts of these changes cannot be determined with certainty at this time. Situations that may impact our costs include the following items:

• On April 5, 2010, there was an explosion at Massey Energy Company’s Upper Big Branch Mine. Although the cause of the explosion is not known and may not be known for some time, as a result of this incident, it is likely that new legislation and regulations will be enacted seeking to improve the safety of underground coal mining operations. Further, it is likely that regulatory authorities will more strictly enforce existing laws and regulations. New safety requirements and enhanced enforcement efforts typically increase the costs of our coal mining operations, which would impact our margins and results of operations.

• Enactment of laws or passage of regulations regarding emissions from combustion of fossil fuels by the U.S., individual states or by other countries could result in decreased consumption of coal and gas and switching to other energy technologies for electricity. It is likely that some form of legislation addressing global climate change will be enacted in the future, however, at this time it is not possible to determine the impact of potential legislation on our operations or financial condition. The level of impact will depend on numerous factors including the specific requirements imposed by legislation, the timing of legislation, time period for compliance, and the timing and commercial development of technologies associated with carbon capture and sequestration. Ultimately, the impact of possible legislation on our business will depend on the degree to which electricity generators are forced to reduce their consumption of coal or gas, install expensive technologies for carbon capture and sequestration, or switch to alternative energy sources. CONSOL Energy believes that if climate change legislation is passed, gas will be impacted to a lesser degree than coal and the Company has made strategic investment decisions to change its portfolio of assets to increase the contribution of gas to the Company’s business. In fact, over the short term, the Company expects gas to be the preferred fuel source for new power plants. Over the long term, CONSOL believes that with the development of new technologies for carbon capture and sequestration, both coal and gas will continue to be used as clean and competitive fuel sources for electric generation.

• On April 1, 2010, the Environmental Protection Agency (EPA) issued detailed guidance to its regional offices to provide clarification of EPA’s expectations regarding EPA review of permits necessary for coal mining activities in the states of Kentucky, West Virginia, Pennsylvania, Virginia, Ohio and Tennessee. The guidance pertains to the EPA’s review of proposed surface water discharge (NPDES) permits under Section 402 of the Clean Water Act, proposed permits for

filling waters of the United States under Section 404 of the Clean Water Act, and the National Environmental Policy Act (NEPA) review of projects covered by NEPA. In the guidance, the EPA creates a number of presumptions and instructs the regional offices to object to permits if the presumptions are implicated. One presumption is that conductivity levels above 500 micromhos per centimeter in streams below coal mining operations are harmful to aquatic insects and therefore violate state water quality standards. The 500 micromhos presumption is at least three times lower than the conductivity level that results from using the EPA’s standard protocol for determining toxicity to aquatic life. (Conductivity is a measurement of the concentration of ionized materials in water.) If this presumption is strictly applied, it will take longer to obtain NPDES permits and valley fill permits for mining operations, or permit applications may be denied. The guidance is likely to be challenged by the coal industry. It is too early to determine the impact of this policy if it remains in effect, but it could materially adversely affect our operations and results of operations.

• Under existing Mine Health and Safety Administration regulations, the installation of higher strength seals to isolate abandoned areas or previously sealed areas of the mine are required. The increase in strength of seals was required to better protect the active sections of the underground mines from explosions, fires, or other situations that may occur within the sealed areas. CONSOL Energy has been replacing existing seals with the higher strength seals over the past two years. We currently estimate approximately 540 seals remaining that need to be replaced over the next two years. The cost of these seals is expensed as incurred.

• As described more fully in “Note 10—Commitments and Contingencies” in Condensed Consolidated Financial Statements of this Form 8-K, Consolidation Coal Company has submitted to the West Virginia Department of Environmental Protection (WVDEP) a plan and schedule which provides for construction of a centralized advanced technology mine water treatment plant by June, 2013 to achieve compliance with chloride effluent limits and in-stream chloride water quality standards in tributaries to the Monongahela River. The cost of the treatment plant may reach or exceed $100,000. Additionally, CCC is currently negotiating a joint Consent Decree with the EPA and the WVDEP that is likely to include the compliance plan and schedule that was submitted to the WVDEP. The Consent Decree is also likely to include civil penalties to settle alleged past violations related to chlorides without an admission of liability. The parties have not yet discussed the amount of a civil penalty. The Consent Decree will provide CCC with a schedule for orderly construction of the advanced water treatment plant and related facilities.

• Health care reform legislation included a revision to coal workers’ pneumoconiosis (CWP) regulations which will enable claimants to more easily qualify for a benefit under these regulations. The legislation also allows for a five-year look back on claims to determine if a previously denied claim will now become eligible. The new legislation will impact CONSOL Energy’s CWP liability, related expense and cashflows.

Although these items primarily impact CONSOL Energy’s coal business, management continues to believe our coal business will be successful in developing economic solutions to address these matters. Our coal business is also expected to continue to generate expanding margins due to:

• Our dramatically improving low-volatile business with our Buchanan Coal Mine,

• Our new high-volatile business, where we are selling Northern Appalachian coal to Asian and Brazilian steelmakers at expanded margins; and

• Our improved thermal business, where the severe winter weather, and our high-volatile sales, have lowered thermal coal stockpiles.

We believe that coal will continue to provide the base load of the nation’s energy needs. Through our efforts during the last 10 years to improve our operating efficiencies at our major coal production sites we are well positioned to continue to provide our customers with low cost, high-British thermal units (btus) coal that we expect will generate returns to our shareholders.

Also, on April 30, 2010, CONSOL Energy closed on the $3.475 billion Dominion Acquisition, with the fair value assigned primarily to the proved and unproven gas reserves and acres acquired. The assets include nearly 1 trillion cubic feet of proved reserves and nearly 500 thousand acres of Marcellus Shale. Nearly all of the Marcellus Shale acreage being acquired is held by production. Such acreage has no drilling commitments, and therefore allows capital to be allocated on the basis of economics, not simply to hold expiring leases. The acquired acreage has a 12.5% royalty, except for about 20 thousand acres held in fee (meaning that it has no royalty). These attributes, when combined with their prime location, lead CONSOL Energy to believe that its Marcellus Shale position is the best in the industry. All of the Marcellus Shale acres are in southwestern Pennsylvania or northern West Virginia. The Pennsylvania Marcellus Shale acreage is concentrated in Indiana, Westmoreland, and Armstrong counties, while the West Virginia acreage is concentrated in Barbour, Lewis, and Upshur counties.

On April 23, 2010, CONSOL Energy amended the accounts receivable securitization facility to allow the Company to receive, on a revolving basis, up to $200,000. Previously, the facility provided up to $165,000 of short-term funding or letters of credit. The trade accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. The facility was expanded to meet the future cash needs of the Company.

On April 28, 2010, CONSOL Energy commenced a tender offer to acquire all of the shares of CNX Gas common stock that it does not currently own at a cash price of $38.25 per share. CONSOL Energy currently owns approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. CONSOL Energy’s offer is subject to a number of conditions, including the condition, which cannot be waived, that there is tendered into the offer at least a majority of the outstanding CNX Gas shares not currently held by CONSOL Energy. Following the purchase by CONSOL Energy of shares of CNX Gas in the offer, CONSOL Energy intends to merge CNX Gas into a wholly owned subsidiary of CONSOL Energy, with CNX Gas surviving the merger as a wholly owned subsidiary of CONSOL Energy. As a result of the merger, each outstanding CNX Gas share will be converted into the right to receive $38.25. CONSOL Energy anticipates financing the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and/or proceeds from its recently closed offering of common stock. Previously, on March 21, 2010, CONSOL Energy announced that it had entered into an agreement with T. Rowe Price Associates, Inc., on behalf of its investment advisory clients owning approximately 9.5 million shares of CNX Gas common stock, or approximately 37% of the shares of CNX Gas that CONSOL Energy does not currently own. Under the agreement, CONSOL Energy agreed, subject to certain conditions, to commence this tender offer and T. Rowe Price agreed to tender these shares of CNX Gas common stock subject to the rights of certain clients with respect to those shares which are discretionary account shares.

Results of Operations

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

Net Income Attributable to CONSOL Energy

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $100 million, or $0.54 per diluted share, for the three months ended March 31, 2010. Net income attributable to CONSOL Energy shareholders was $196 million, or $1.08 per diluted share, for the three months ended March 31, 2009. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.

The coal segment includes steam coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The steam coal aggregated segment includes Blacksville #2, Robinson Run, Emery, the Fola Complex, McElroy, Loveridge, Bailey, Enlow Fork, Shoemaker, the Miller Creek Complex and Buchanan steam sales. The aggregate high volatile coal segment includes Bailey, Enlow Fork, the Fola Complex and Emery coal sales. The aggregate low volatile coal segment includes the Buchanan mine. The other coal segment includes our purchased coal activities, idled mine activities, and other activities assigned to the coal segment but not allocated to each individual mine.

The gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. The segments are determined based on activities from target strata. The other gas segment includes royalty interest activities, purchased gas activities and other activities assigned to the gas segment but not allocated to each individual component.

The other segment includes industrial supplies activity, terminal and river service activity, income taxes and other business activities not assigned to the coal or gas segment.

TOTAL COAL SEGMENT ANALYSIS for the three months ended March 31, 2010 compared to the three months ended March 31, 2009:

The coal segment contributed $113 million of earnings before income taxes in the three months ended March 31, 2010 compared to $198 million in the 2009 period. Variances by the individual coal segments are discussed below.

	For the Three Months Ended March 31, 2010											Difference to Three Months Ended March 31, 2009
	Steam Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam Coal			High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal
Sales:
Produced Coal	$	717	$	57	$	126	$	—		$	900	$	(118	)	$	57	$	57	$	—		$	(4	)
Purchased Coal		—		—		—		22			22		—			—		—		8			8
Total Outside Sales		717		57		126		22			922		(118	)		57		57		8			4
Freight Revenue		—		—		—		31			31		—			—		—		—			—
Other Income		1		1		—		12			14		—			1		—		(4	)		(3	)
Total Revenue and Other Income		718		58		126		65			967		(118	)		58		57		4			1
Costs and Expenses:
Total operating costs		402		20		63		95			580		(20	)		20		30		22			52
Total provisions		51		3		7		37			98		3			3		2		23			31
Total administrative & other costs		34		1		4		23			62		—			1		—		(2	)		(1	)
Depreciation, depletion and amortization		64		3		4		12			83		(1	)		3		—		2			4
Total Costs and Expenses		551		27		78		167			823		(18	)		27		32		45			86
Freight Expense		—		—		—		31			31		—			—		—		—			—
Total Cost		551		27		78		198			854		(18	)		27		32		45			86
Earnings Before Income Taxes	$	167	$	31	$	48	$	(133	)	$	113	$	(100	)	$	31	$	25	$	(41	)	$	(85	)

STEAM COAL SEGMENT

The steam coal segment contributed $167 million to total company earnings before income tax in the three months ended March 31, 2010 compared to $267 million in the three months ended March 31, 2009.

Steam coal revenue was $717 million in the three months ended March 31, 2010 compared to $835 million in the three months ended March 31, 2009. The $118 million decrease was attributable to lower sales volumes of steam coal sold and lower average sales prices.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		13.1		14.8		(1.7	)	(11.5	)%
Average Sales Price Per Steam Ton Sold	$	54.72	$	56.45	$	(1.73	)	(3.1	)%

Steam coal sales tons are lower in the period-to-period comparison primarily due to the idling of Mine 84 and Jones Fork mines. Lower average sales prices for steam coal reflects the roll-off of higher priced contracts signed in the latter half of 2008. Steam coal inventory was 3.8 million tons at March 31, 2010 compared to 2.9 million tons at December 31, 2009.

Other income attributable to the steam coal segment represents earnings from our equity affiliates that operate steam coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the steam coal segment were $402 million in the three months ended March 31, 2010 compared to $422 million in the three months ended March 31, 2009. Operating costs, on a dollar basis, related to the steam coal segment have decreased primarily due to lower production from contract mines and reduced operating supplies and maintenance. Operating costs, on a per unit basis, have increased primarily due to the reduced amount of tons sold. Fixed costs incurred at our mining operations were spread over fewer tons sold, which negatively impacted average unit costs.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		13.1		14.8		(1.7	)	(11.5	)%
Average Operating Cost Per Steam Ton Sold	$	30.70	$	28.53	$	2.17		7.6	%

Higher average operating costs per unit for steam coal tons sold is primarily related to the following items:

• Steam coal costs per unit are higher in the 2010 period as a result of lower cost structure mines, such as Bailey and Enlow Fork, selling coal on the high volatile metallurgical market. This impacted the steam coal segment due to the proportionately lower tons sold from the lower cost structure mines included in this segment, leaving more tons sold from higher cost structure mines remaining. This has negatively impacted unit costs on the steam coal segment.

• Labor costs have increased due to the effects of wage increases at the union mines from the current labor contracts. These contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-union mines. Employee counts have also increased at our active mining operations in order to meet our staffing needs.

• Subsidence costs have increased related to additional structures impacted by longwall mining in the 2010 period compared to the 2009 period. These costs vary from period-to-period depending on density and value of structures being impacted by the operation of the mine.

• Health and retirement costs related to the active hourly work force have increased attributable to an increase in the contribution to the multiemployer 1974 pension trust that is required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America (UMWA) in the 2009 period to $5.00 per hour in the 2010 period. Contributions to this multiemployer plan are expensed as incurred. These costs have also increased in the period-to-period comparison due to higher medical costs for the active hourly work force.

• Power costs have increased attributable to various rate increases that occurred throughout our operations.

• These increases in costs per ton sold were offset, in part, by a reduction in contract mining fees due to a reduction in tons produced at contractor locations in the period-to-period comparison.

Total provisions are made up of the expenses related to the company’s long-term liabilities such as other post employment benefits (OPEB), the salary retirement plan, workers’ compensation, long-term disability and mine closing and related liabilities. With the exception of mine closing and related liabilities accretion expense, these liabilities are actuarially calculated for the company as a whole. The expenses associated with these costs are allocated to operational units based on active employee counts or active salary dollars. Mine closing and related liabilities accretion expense is calculated on a mine-by-mine basis. The provision expense attributable to the steam coal segment was $51 million in the three months ended March 31, 2010 compared to $48 million in the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		13.1		14.8		(1.7	)	(11.5	)%
Average Provision Costs Per Steam Ton Sold	$	3.87	$	3.25	$	0.62		19.1	%

Provision costs per unit have increased in the period-to-period comparison due primarily to higher actuarial liability expenses for the total company explained below. Although the percentage of these expenses allocated to the steam coal segment is lower in the current quarter, the overall increase in company costs has increased the total dollars allocated to the steam segment which negatively impacts the per unit costs as a result of the lower produced steam tons sold.

Total CONSOL Energy expenses related to our actuarial liabilities were $73 million in the three months ended March 31, 2010 compared to $64 million for the three months ended March 31, 2009. The increase of $9 million is due primarily to changes in the discount rates used at the measurement dates.

Total administrative and other costs include selling expenses, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to the mines on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Total administrative and other costs related to the steam coal segment were $34 million in both the three months ended March 31, 2010 and 2009.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		13.1		14.8		(1.7	)	(11.5	)%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.54	$	2.35	$	0.19		8.1	%

Total company selling, general and administrative costs are flat in the period-to-period comparison. The increase in the per unit costs are the result of the lower produced steam tons sold in the period-to-period comparison.

Depreciation, depletion and amortization was $64 million in the three months ended March 31, 2010 compared to $63 million in the three months ended March 31, 2009. The increase in average unit costs was the result of the lower produced steam tons sold in the period-to-period comparison.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		13.1		14.8		(1.7	)	(11.5	)%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.92	$	4.34	$	0.58		13.4	%

Higher average unit costs for depreciation, depletion and amortization were primarily attributable to the lower tons sold increasing the per unit impact of straight-line depreciation charges to the steam coal segment. Straight-line depreciation is primarily related to mining equipment used in production at the steam coal mines.

HIGH VOL METALLURGICAL COAL SEGMENT

The high vol metallurgical (met) coal segment contributed $31 million to total company earnings before income tax in the three months ended March 31, 2010. There was no activity in this segment in the prior period. This is a new market that has developed in the 2010 period and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical coal markets.

The high vol met coal segment sales revenue was $57 million in the three months ended March 31, 2010. Strength in the met coal market has allowed for the export of Northern Appalachian coal, historically sold domestically on the steam coal market, to crossover to the Brazil and Asia metallurgical coal markets.

	2010 Period		2009 Period		Variance		Percentage Change
Produced High Vol Met Tons Sold (in millions)		0.8		—		0.8	100.0	%
Average Sales Price Per High Vol Met Ton Sold	$	75.70	$	—	$	75.70	100.0	%

Other income attributable to the high vol coal segment represents earnings from our equity affiliates that operate high vol mines. The equity in earnings of affiliates is insignificant to the total segment activity.

Total high vol coal segment costs were $27 million in the three months ended March 31, 2010. The cost components on a per unit basis are as follows:

	2010 Period		2009 Period		Variance		Percentage Change
Produced High Vol Met Tons Sold (in millions)		0.8		—		0.8	100.0	%
Average Operating Cost Per High Vol Met Ton Sold	$	27.62	$	—	$	27.62	100.0	%
Average Provision Cost Per High Vol Met Ton Sold	$	3.11	$	—	$	3.11	100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	1.87	$	—	$	1.87	100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	3.89	$	—	$	3.89	100.0	%

The high vol met coal segment has increased the margin on our coal production that would have otherwise been sold in the domestic steam market.

LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical (met) coal segment contributed $48 million to the total company earnings before income tax in the three months ended March 31, 2010 compared to $23 million in the three months ended March 31, 2009. The increase is due primarily to the Buchanan mine operating for the entire 2010 period. The Buchanan mine was idled for the entire month of March 2009 as well as operated fewer shifts in January and February 2009 in response to the economic crisis that significantly lowered the demand for low volatile metallurgical coal. This lower demand in the 2009 period was due to a drop in steel demand.

The low vol met coal segment sales revenue was $126 million in the three months ended March 31, 2010 compared to $69 million in the three months ended March 31, 2009. Higher sales revenues were due to higher tons sold partially offset by lower average sales prices.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Low Vol Metallurgical Tons Sold (in millions)		1.2		0.5		0.7		140.0	%
Average Sales Price Per Low Vol Metallurgical Ton Sold	$	105.54	$	148.69	$	(43.15	)	(29.0	)%

The decrease in average sales price per low vol met ton sold reflects lower prices realized due to a downturn in the domestic and international steel business.

Total costs for the low vol met coal segment were $78 million for the three months ended March 31, 2010 compared to $46 million for the three months ended March 31, 2009. A meaningful comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low vol met coal segment in 2009 as discussed above. The improvements in unit costs are related to operating the Buchanan mine throughout the three months ended March 31, 2010. The 2009 unit costs are not representative of the operating mine due to fixed costs being spread over significantly fewer tons. The 2010 period costs are representative of normal costs for this segment.

	2010 Period		2009 Period		Variance			Percentage Change
Produced Low Vol Metallurgical Tons Sold (in millions)		1.2		0.5		0.7		140.0	%
Average Operating Cost Per Low Vol Met Ton Sold	$	52.22	$	72.27	$	(20.05	)	(27.7	)%
Average Provision Per Low Vol Met Ton Sold	$	5.65	$	10.83	$	(5.18	)	(47.8	)%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	3.37	$	7.50	$	(4.13	)	(55.1	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	3.76	$	8.10	$	(4.34	)	(53.6	)%

OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before income tax by $133 million in the three months ended March 31, 2010 compared to a negative $92 million in the three months ended March 31, 2009. The Other Coal segment includes purchased coal activities, closed and idle mine costs and miscellaneous transactions that are directly related to the coal segment.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The revenues were $22 million in the three months ended March 31, 2010 compared to $14 million in the three months ended March 31, 2009. The increase was primarily due to higher volumes of purchased coal tons sold, offset, in part, by lower sales prices.

Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue is directly offset in freight expense. Freight revenue was $31 million in both the three months ended March 31, 2010 and 2009.

Miscellaneous other income was $12 million in the three months ended March 31, 2010 compared to $16 million in the three months ended March 31, 2009. The $4 million decrease consists of the following items:

• Mark-to-market adjustments for free standing coal sales options resulted in approximately $2 million reversal in the 2009 period of previously recognized unrealized losses. These options expired during the year ended December 31, 2009.

• Other miscellaneous income decreased $2 million in the period-to-period comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total cost was $198 million in the three months ended March 31, 2010 compared to $153 million in the three months ended March 31, 2009. The increase of $45 million is due to the following items:

• Closed and idle mine costs increased approximately $15 million in the period-to-period comparison. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia is expected to increase. Our initial belief is that as a result of the changes in mine plans and because mining is some areas is anticipated to be curtailed earlier than originally anticipated, the quantity of material required to reclaim the operation in its present state will be increased. As of this time, no detailed reclamation plan has been developed and the definitive costs associated with the increased reclamation are not available, however, our initial estimates indicate the reclamation liability could equal or exceed an additional $25 million. As a result, $25 million of expense was recognized in the 2010 period. Detailed reclamation plans and mining plans are being developed to determine the impacts of these revised plans on the associated reclamation liability. This increase was offset, in part, by approximately $10 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in the 2010 period. Shoemaker mine was idled throughout the 2009 period while the track haulage system was converted to a belt haulage system. This mine has been in production throughout most of the 2010 period. Mine 84 and the Jones Fork Complex operated throughout most of the 2009 period, but these locations were idled throughout the 2010 period.

• Litigation settlements increased approximately $22 million in the period-to-period comparison. The settlement represents the loss on the sale of the Jones Fork operation which was sold in relation to an option granted as a settlement of litigation. Also, legal settlements include additional expense related to contingencies recognized for various litigation issues as discussed in “Note 10—Commitments and Contingencies” Condensed Consolidated Financial Statements of Form 8-K.

• Purchased coal costs consist of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. The increase of $10 million in purchased coal costs in the 2010 period was primarily due to higher volumes purchased.

• Other expenses related to the coal segment were $2 million lower in the three months ended March 31, 2010 compared to the three months ended March 31, 2009. These decreases were related to various transactions that were incurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the three months ended March 31, 2010 compared to the three months ended March 31, 2009:

The Total Gas segment contributed $74 million to earnings before income tax in the three months ended March 31, 2010 compared to $89 million in the three months ended March 31, 2009. A detailed variance explanation is described below.

	For the Three Months Ended March 31, 2010											Difference to Three Months Ended March 31, 2009
	CBM		Conven- tional		Marcellus		Other Gas			Total Gas		CBM			Conven- tional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	161	$	3	$	8	$	1		$	173	$	5		$	—		$	7	$	(1	)	$	11
Related Party		1		—		—		—			1		—			—			—		—			—
Total Outside Sales		162		3		8		1			174		5			—			7		(1	)		11
Gas Royalty Interest		—		—		—		14			14		—			—			—		2			2
Purchased Gas		—		—		—		3			3		—			—			—		1			1
Other Income		—		—		—		1			1		—			—			—		(1	)		(1	)
Total Revenue and Other Income		162		3		8		19			192		5			—			7		1			13
Lifting		13		1		—		—			14		2			1			—		—			3
Gathering		24		—		2		1			27		3			(1	)		1		1			4
General & Administration		15		—		1		—			16		(1	)		(1	)		1		—			(1	)
Depreciation, Depletion and Amortization		27		1		3		1			32		5			—			3		1			9
Gas Royalty Interest		—		—		—		12			12		—			—			—		1			1
Purchased Gas		—		—		—		2			2		—			—			—		—			—
Exploration and Other Costs		—		—		—		4			4		—			—			—		2			2
Other Corporate		—		—		—		9			9		—			—			—		9			9
Interest Expense		—		—		—		2			2		—			—			—		—			—
Total Cost		79		2		6		31			118		9			(1	)		5		14			27
Earnings Before Noncontrolling Interest and Income Tax		83		1		2		(12	)		74		(4	)		1			2		(13	)		(14	)
Noncontrolling Interest		—		—		—		—			—		—			—			—		1			1
Earnings Before Income Tax	$	83	$	1	$	2	$	(12	)	$	74	$	(4	)	$	1		$	2	$	(14	)	$	(15	)

COALBED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed approximately $83 million to the total company earnings before income tax in the three months ended March 31, 2010 compared to $87 million in the three months ended March 31, 2009. The decrease is due to the following items.

CBM sales revenues increased $5 million from $157 million in the three months ended March 31, 2009 to $162 million in the three months ended March 31, 2010. The increase was primarily due to a 3.8% increase in volumes sold, offset, in part by a 1.6% decrease in average sales price per thousand cubic feet.

	2010 Period		2009 Period		Variance			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		21.9		21.1		0.8		3.8	%
Average CBM Sales Price per thousand cubic feet sold	$	7.39	$	7.51	$	(0.12	)	(1.6	)%

CBM sales volumes increased 1.2 billion cubic feet as a result of additional wells coming online from our ongoing drilling program, offset by approximately 0.4 billion cubic feet of production that was deferred due to the loss of power for several days related to a severe winter storm in our Northern Appalachian producing region in the 2010 period. The decrease in average sales price is the result of various gas swap transactions throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 13.0 billion cubic feet of our produced gas sales volumes for the three months ended March 31, 2010 at an average price of $8.76 per thousand cubic feet. In the three months ended March 31, 2009, these financial hedges represented approximately 10.7 billion cubic feet at an average price of $9.85 per thousand cubic feet. Although average market prices have increased slightly in the period-to-period comparison, we have sold more hedged volumes at lower average prices in the 2010 period compared to the 2009 period.

CBM lifting costs were $13 million in the three months ended March 31, 2010. This reflects an increase of $2 million due primarily to an 11.5% increase in average CBM unit costs and a 3.8% increase in sales volumes.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		21.9		21.1		0.8	3.8	%
Average CBM lifting costs per thousand cubic feet sold	$	0.58	$	0.52	$	0.06	11.5	%

Average CBM lifting costs per unit increased in the 2010 period as a result of the following:

• Severance taxes, which are included in lifting costs, have increased $0.09 per thousand cubic feet. The 2009 period included a $0.11 per thousand cubic feet reduction related to a revised estimate of pending litigation.

• Idle rig costs have increased $0.03 per thousand cubic feet due to one additional month of idle rig expense in the 2010 period due to idle charges not beginning until February 2009. Idle rig expenses have also increased due to higher monthly fees in 2010 compared to 2009 when the rig was initially idled.

These increases in costs were offset, in part, by the following items:

• Water disposal costs decreased $0.04 per thousand cubic feet due to recycling salt water produced from our wells to be used in fracing new wells. Previously, fees were incurred to dispose of the salt water produced from our wells.

• Other costs decreased $0.02 per thousand cubic feet for various items that occurred throughout both periods, none of which were individually material.

CBM gathering and compression costs were $24 million in the three months ended March 31, 2010, or a $3 million increase in the period-to-period comparison. The increase reflects 3.8% of additional volumes and a 15.0% increase in average CBM gathering and compression unit costs.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		21.9		21.1		0.8	3.8	%
Average CBM gathering and compression costs per thousand cubic feet sold	$	1.15	$	1.00	$	0.15	15.0	%

Average CBM gathering and compression costs per unit increased in the 2010 period as a result of the following:

• Power and fuel costs increased $0.08 per thousand cubic feet due to higher rates being charged by the power producer, additional compressors and an additional processing plant being placed in service during the 2010 period.

• Firm transportation costs have increased $0.07 per thousand cubic feet due to acquiring additional capacity in the Southwest Pennsylvania region in the 2010 period compared to the 2009 period.

CBM general and administrative costs were $15 million in the three months ended March 31, 2010, which reflects a decrease of $1 million in the period-to-period comparison.

	2010 Period		2009 Period		Variance			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		21.9		21.1		0.8		3.8	%
Average CBM general and administrative costs per thousand cubic feet sold	$	0.70	$	0.74	$	(0.04	)	(5.4	)%

General and administrative costs attributable to the Total Gas segment have remained consistent in the period-to-period comparison. General and administrative costs attributable to the Total Gas segment are allocated to the individual gas segments based

on production. Although total general and administrative costs remained consistent in the period-to-period comparison, the percentage allocated to CBM is lower based on CBM production volumes to total gas production volumes in the current period. The lower amount allocated to the CBM segment coupled with additional production in the period-to-period comparison lowered unit costs.

Depreciation, depletion and amortization was $27 million in the three months ended March 31, 2010, or $5 million higher than the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		21.9		21.1		0.8	3.8	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet	$	1.27	$	0.99	$	0.28	28.3	%

There was approximately $22 million, or $0.99 per unit-of-production, of depreciation, depletion and amortization related to the CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended March 31, 2010. The production portion of depreciation, depletion and amortization was $16 million, or $0.74 per unit-of-production in the three months ended March 31, 2009. The CBM unit-of-production rate increased due to revised rates which are generally calculated at the previous year end using the net book value of assets divided by either proved or proved developed reserves. There was approximately $5 million, or $0.28 per thousand cubic feet of depreciation related to gathering and other equipment that is reflected on a straight-line basis in the three months ended March 31, 2010. The non-production related depreciation was $6 million, or $0.25 per thousand cubic feet in the three months ended March 31, 2009. The increase was related to additional gathering assets placed in service after the 2009 period.

CONVENTIONAL GAS SEGMENT

The conventional gas segment contributed approximately $1 million to the total company earnings before income tax in the three months ended March 31, 2010. The conventional gas segments contribution to earnings before income tax was insignificant in the three months ended March 31, 2009.

Conventional gas sales revenue was $3 million in both the three months ended March 31, 2010 and 2009. Total costs for the Conventional gas segment were $2 million, or a decrease of $1 million in the period-to-period comparison. A meaningful comparison of unit revenues and costs cannot be made because of the low volumes produced and sold from the Conventional gas segment.

	2010 Period		2009 Period		Variance			Percentage Change
Produced gas Conventional sales volumes (in billion cubic feet)		0.5		0.4		0.1		25.0	%
Average Conventional sales price per thousand cubic feet sold	$	5.70	$	3.79	$	1.91		50.4	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.80	$	0.50	$	1.30		260.0	%
Average Conventional gathering and compression costs per thousand cubic feet sold	$	0.54	$	0.65	$	(0.11	)	(16.9	)%
Average Conventional general and administrative costs per thousand cubic feet sold	$	0.32	$	0.73	$	(0.41	)	(56.2	)%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.50	$	2.11	$	0.39		18.5	%

MARCELLUS GAS SEGMENT

The Marcellus gas segment contributed approximately $2 million to the total company earnings before income tax in the three months ended March 31, 2010. The Marcellus gas segments contribution to earnings before income tax was insignificant in the three months ended March 31, 2009.

Marcellus gas sales revenue was $8 million in the three months ended March 31, 2010 or an improvement of $7 million in the period to period comparison.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		1.4		0.3		1.1	366.7	%
Average Marcellus sales price per thousand cubic feet sold	$	5.53	$	4.67	$	0.86	18.4	%

Marcellus sales volumes increased 1.3 billion cubic feet primarily due to additional wells coming online from our ongoing drilling program, offset by approximately 0.2 billion cubic feet of production that was deferred due to the loss of power for several days related to a severe winter storm in our Northern Appalachian producing region in the 2010 period. Average sales prices for Marcellus gas was up 18.4% in the period-to-period comparison reflecting the increase in general market prices.

Marcellus lifting costs were insignificant in both the three months ended March 31, 2010 and 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		1.4		0.3		1.1	366.7	%
Average Marcellus lifting costs per thousand cubic feet	$	0.35	$	0.34	$	0.01	2.9	%

Average Marcellus lifting costs per unit were higher in the 2010 period primarily due to salt water disposal costs. Higher salt water disposal costs were related to higher volumes of water produced as in the period-to-period comparison.

Gathering and compression costs were $2 million in the three months ended March 31, 2010, or $1 million higher than the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		1.4		0.3		1.1	366.7	%
Average Marcellus gathering and compression costs per thousand cubic feet sold	$	1.21	$	0.64	$	0.57	89.1	%

Average gathering and compression costs per unit have increased 89.1%, or $0.57 per thousand cubic feet, primarily due to the increased volumes in the period-to-period comparison.

General and administrative costs attributed to the Marcellus segment were $1 million in the three months ended March 31, 2010, or $1 million higher than the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		1.4		0.3		1.1	366.7	%
Average Marcellus general and administrative costs per thousand cubic feet sold	$	0.66	$	0.11	$	0.55	500.0	%

General and administrative costs attributable to the total gas segment are allocated to the various gas segments based on production. Total general and administrative costs have remained consistent in the period-to-period comparison. Although total general and administrative costs remained consistent in the period-to-period comparison, the percentage allocated to the Marcellus segment is higher based on Marcellus production volumes to total gas production volumes in the current period.

Depreciation, depletion and amortization was $3 million in the three months ended March 31, 2010, or $3 million higher than the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		1.4		0.3		1.1	366.7	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.86	$	1.29	$	0.57	44.2	%

There was approximately $3 million, or $1.70 per unit-of-production of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended March 31, 2010. Units-of-production depreciation, depletion and amortization was insignificant on a dollar basis in the three months ended March 31, 2009, or $1.22 per thousand cubic feet. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. Prior to September 30, 2009, depreciation, depletion and amortization rates were not broken down into types of well, instead one pool with all types of wells was used. Therefore, the 2009 rate was a blended rate for all well types. During the quarter ended September 30, 2009, rates were developed for each type of well. The non-production related depreciation was insignificant but resulted in $0.16 per thousand cubic feet per unit cost related to gathering and other equipment that is reflected on a straight-line basis in the three months ended March 31, 2010. The non-production related depreciation was insignificant but resulted in $0.07 per thousand cubic feet per unit cost related to gathering and other equipment in the three months ended March 31, 2009. Due to the low volumes of Marcellus gas produced in the 2009 period, minimal gathering depreciation was allocated to this segment.

OTHER GAS SEGMENT

The other gas segment includes activity not assigned to the CBM, conventional or Marcellus gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses and miscellaneous operational activity not assigned to a specific gas segment.

Other gas sales volumes are primarily related to the production from the Chattanooga Shale in Tennessee. Revenues from this operation were approximately $1 million in the three months ended March 31, 2010. Revenues were approximately $2 million in the three months ended March 31, 2009. Total costs related to these other sales were $2 million in the 2010 period and were insignificant in the 2009 period. The increase in costs in the period-to-period comparison were primarily attributable to higher volumes produced. A per unit analysis of the other operating costs is not meaningful due to the low volumes produced in the period-to-period comparison.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the gas segment. The changes in market prices, contractual differences among leases and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales revenues were $14 million in the three months ended March 31, 2010 compared to $12 million in the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Royalty Interest gas sales volumes (in billion cubic feet)		2.5		2.2		0.3	13.6	%
Average Sales Price per thousand cubic feet sold	$	5.82	$	5.65	$	0.17	3.0	%

Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $3 million in the three months ended March 31, 2010 compared to $2 million in the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Purchased Gas sales volumes (in billion cubic feet)		0.4		0.3		0.1	33.3	%
Average Sales Price per thousand cubic feet sold	$	5.76	$	5.75	$	0.01	0.2	%

Other income was $1 million in the three months ended March 31, 2010 compared to $2 million in the three months ended March 31, 2009. The decrease of $1 million was due to various transactions that occurred throughout both periods, none of which were individually material.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the gas segment. The changes in market prices, contractual differences among leases and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas costs were $12 million in the three months ended March 31, 2010 compared to $11 million in the three months ended March 31, 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Royalty Interest gas sales volumes (in billion cubic feet)		2.5		2.2		0.3	13.6	%
Average Cost Price per thousand cubic feet	$	4.95	$	4.74	$	0.21	4.4	%

Purchased gas cost volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas cost volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $2 million in both the three months ended March 31, 2010 and 2009.

	2010 Period		2009 Period		Variance		Percentage Change
Purchased Gas volumes (in billion cubic feet)		0.4		0.3		0.1	33.3	%
Average Cost Price per thousand cubic feet sold	$	6.04	$	4.42	$	1.62	36.7	%

Exploration and other costs have increased $2 million in the period-to-period comparison. The increase in these costs were due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

	2010 Period		2009 Period		Dollar Variance		Percentage Change
Dry hole and other costs	$	2	$	1	$	1	100.0	%
Exploration expenses		2		1		1	100.0	%
Total Exploration and Other Costs	$	4	$	2	$	2	100.0	%

Other corporate expenses have increased due to the following items:

	2010 Period		2009 Period			Dollar Variance		Percentage Change
Stock-based compensation	$	3	$	(3	)	$	6	(200.0	)%
Short-term incentive compensation		4		3			1	33.3	%
Miscellaneous		2		—			2	100.0	%
Total Other Corporate Expenses	$	9	$	—		$	9	100.0	%

Stock-based compensation expense has increased $6 million primarily due to the conversion of the CNX Gas long-term incentive compensation plan to CONSOL Energy restricted stock units in the 2009 period. The conversion resulted in a reduction of approximately $4 million of expense in the 2009 period. The additional $2 million of expense is related to the stock-based compensation expenses allocated from CONSOL Energy in the 2010 period.

The short-term incentive compensation program is designed to increase compensation to eligible employees when the gas segment reaches predetermined targets for production unit cost and safety goals. Short-term incentive compensation expense is higher in the 2010 period due to improved performance relative to targets.

Interest expense has remained consistent in the period-to-period comparison.

Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which the gas segment holds no ownership interest, but is the primary beneficiary. The gas segment has been determined to be the primary beneficiary due to guarantees of the third party’s bank debt related to the purchase of drilling rigs and the third party entity provides drilling services primarily to the gas segment. The gas segment consolidates the entity and then reflects 100% of the impact as noncontrolling interest. The consolidation does not significantly impact any amounts reflected in the gas segment income statement. The variance in the noncontrolling interest amounts reflects the third party’s variance in earnings in the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the three months ended March 31, 2010 compared to the three months ended March 31, 2009:

The other segment includes activity from sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment negatively contributed $45 million to total company earnings before income tax in the three months ended March 31, 2010 compared to a negative $3 million in the three months ended March 31, 2009. The other segment also includes total company income tax expense of $35 million in the three months ended March 31, 2010 compared to $80 million in the three months ended March 31, 2009.

	2010 Period			2009 Period			Variance			Percentage Change
Sales-Outside	$	74		$	69		$	5		7.2	%
Other Income		8			4			4		100.0	%
Total Revenue		82			73			9		12.3	%
Cost of Goods Sold and Other Charges		119			68			51		75.0	%
Depreciation, Depletion & Amortization		5			5			—		0.0	%
Taxes Other Than Income Tax		3			3			—		0.0	%
Total Costs		127			76			51		67.1	%
Earnings Before Income Tax		(45	)		(3	)		(42	)	(1400.0	)%
Income Tax		35			80			(45	)	(56.3	)%
Net Income	$	(80	)	$	(83	)	$	3		3.6	%

Industrial supplies:

Total revenue from industrial supplies were $50 million in both the three months ended March 31, 2010 and 2009. Total costs related to industrial supplies were $48 million in both the three months ended March 31, 2010 and 2009.

Transportation operations:

Total revenue related to the transportation operations were $25 million in the three months ended March 31, 2010 compared to $22 million in the three months ended March 31, 2009. The increase was primarily attributable t additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Total costs related to the transportation operations were $20 million in the three months ended March 31, 2010 compared to $19 million in the three months ended March 31, 2009. The increase of $1 million was related to the additional through-put tons handled by these operations.

Miscellaneous other:

Additional total revenue of $7 million was recognized in the other segment in the three months ended March 31, 2010 compared to $1 million in the three months ended March 31, 2009. The increase of $6 million was attributable to the successful resolution of an outstanding tax issue with the Canadian Revenue Authority for the years 1997 through 2003 in which CONSOL Energy will be entitled to interest on the tax refund.

Other corporate costs in the other segment include interest cost, acquisition and financing costs and various other corporate charges. Total other costs were $59 million in the three months ended March 31, 2010 compared to $9 million in the three months ended March 31, 2009. Other corporate costs increased $50 million due to the following items:

• Financing and acquisition fees of $47 million were incurred in the three months ended March 31, 2010 related to the Dominion Acquisition and the corresponding financing arrangements. The fees include $35 million of bank fees for a bridge loan that was required under the purchase and sale agreement with Dominion, $8 million of legal fees for the acquisition and the financing arrangements, $2 million for bank fees related to amending the credit facilities to all the acquisition, and $2 million for various other fees. The equity offering was completed on March 31, 2010 and resulted in approximately $1.8 billion of proceeds (44.3 million shares were issued). The debt offering was completed on April 1, 2010 and resulted in the issuance of approximately $3 billion of bonds and generated net proceeds of $2.7 billion. The Dominion Acquisition for $3.475 billion closed on April 30, 2010.

• Other corporate items increased $3 million due to various transactions that occurred throughout both periods, none of which were individually material.

The effective income tax rate was 24.1% in the three months ended March 31, 2010 compared to 28.0% in the three months ended March 31, 2009. The decrease in the effective tax rate was attributable to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impact the benefit of percentage depletion on the effective tax rate. The current tax rate is also impacted by the acquisition and financing fees which are not deductible for tax purposes. See “Note 5—Income Taxes” of the Condensed Consolidated Financial Statements of this Form 8-K.

	2010 Period			2009 Period			Variance			Percentage Change
Total Company Earnings Before Income Taxes	$	142		$	285		$	(143	)	(50.2	)%
Income Tax Expense	$	34		$	80		$	(46	)	(57.5	)%
Effective Income Tax Rate		24.1	%		28.0	%		(3.9	) %

EX-99.3

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.

4

(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.

7

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.

8

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.

9

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.

10

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.

11

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.

12

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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