10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the quarterly period ended September 30, 2010

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 001-14901

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware	51-0337383
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Indicate by check mark whether the registrant:(1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  x    No   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller Reporting Company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Class	Shares outstanding as of October 25, 2010
Common stock, $0.01 par value	225,844,598

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION
Item 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and nine months ended September 30, 2010 and 2009		3
	Consolidated Balance Sheets at September 30, 2010 and December 31, 2009		4
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2010		6
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009		7
	Notes to Unaudited Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		88
Item 4.	Controls and Procedures		90
PART II OTHER INFORMATION
Item 1.	Legal Proceedings		91
Item 5.	Other Information		91
Item 6.	Exhibits		93

2

PART I

FINANCIAL INFORMATION

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 September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
Sales—Outside	$	1,260,499	$	1,022,617		$	3,650,129		$	3,167,002
Sales—Gas Royalty Interests		18,131		8,443			46,621			29,741
Sales—Purchased Gas		3,524		1,471			8,280			4,102
Freight—Outside		37,269		36,130			96,544			94,133
Other Income		29,870		25,856			77,126			88,855
Total Revenue and Other Income		1,349,293		1,094,517			3,878,700			3,383,833
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		850,819		707,256			2,436,452			2,017,735
Acquisition and Financing Fees		337		—			64,415			—
Gas Royalty Interests Costs		16,408		6,268			40,133			23,317
Purchased Gas Costs		3,333		1,103			6,980			3,023
Freight Expense		37,269		36,130			96,544			94,133
Selling, General and Administrative Expenses		38,722		31,642			107,897			98,084
Depreciation, Depletion and Amortization		161,429		109,965			413,379			323,659
Interest Expense		66,430		7,502			139,613			22,959
Taxes Other Than Income		83,406		66,146			243,831			214,457
Total Costs		1,258,153		966,012			3,549,244			2,797,367
Earnings Before Income Taxes		91,140		128,505			329,456			586,466
Income Taxes		15,757		35,219			75,291			169,370
Net Income		75,383		93,286			254,165			417,096
Less: Net Income Attributable to Noncontrolling Interest		—		(5,916	)		(11,845	)		(20,568	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	75,383	$	87,370		$	242,320		$	396,528
Earnings Per Share:
Basic	$	0.33	$	0.48		$	1.15		$	2.20
Dilutive	$	0.33	$	0.48		$	1.13		$	2.17
Weighted Average Number of Common Shares Outstanding:
Basic		225,781,539		180,725,194			211,235,893			180,649,268
Dilutive		228,092,299		183,191,667			213,638,176			182,751,922
Dividends Paid Per Share	$	0.10	$	0.10		$	0.30		$	0.30

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

3

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	(Unaudited) September 30, 2010		December 31, 2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	15,582	$	65,607
Accounts and Notes Receivable:
Trade		225,241		317,460
Other Receivables		19,502		15,983
Accounts Receivable—Securitized		200,000		50,000
Inventories		262,331		307,597
Deferred Income Taxes		86,489		73,383
Recoverable Income Taxes		27,907		—
Prepaid Expenses		163,709		161,006
Total Current Assets		1,000,761		991,036
Property, Plant and Equipment:
Property, Plant and Equipment		14,737,790		10,681,955
Less—Accumulated Depreciation, Depletion and Amortization		4,747,384		4,557,665
Total Property, Plant and Equipment—Net		9,990,406		6,124,290
Other Assets:
Deferred Income Taxes		396,347		425,297
Investment in Affiliates		92,261		83,533
Other		241,983		151,245
Total Other Assets		730,591		660,075
TOTAL ASSETS	$	11,721,758	$	7,775,401

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

4

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

	(Unaudited) September 30, 2010			December 31, 2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	312,910		$	269,560
Short-Term Notes Payable		213,900			472,850
Current Portion of Long-Term Debt		15,917			45,394
Accrued Income Taxes		—			27,944
Borrowings Under Securitization Facility		200,000			50,000
Other Accrued Liabilities		797,137			612,838
Total Current Liabilities		1,539,864			1,478,586
Long-Term Debt:
Long-Term Debt		3,140,764			363,729
Capital Lease Obligations		57,291			59,179
Total Long-Term Debt		3,198,055			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		2,686,204			2,679,346
Pneumoconiosis Benefits		187,049			184,965
Mine Closing		391,082			397,320
Gas Well Closing		110,137			85,992
Workers’ Compensation		159,187			152,486
Salary Retirement		144,677			189,697
Reclamation		70,951			27,105
Other		136,923			132,517
Total Deferred Credits and Other Liabilities		3,886,210			3,849,428
TOTAL LIABILITIES		8,624,129			5,750,922
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 225,802,859 Outstanding at September 30, 2010; 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009		2,273			1,830
Capital in Excess of Par Value		2,159,159			1,033,616
Preferred Stock, 15,000,000 authorized, None issued and outstanding		—			—
Retained Earnings		1,617,769			1,456,898
Accumulated Other Comprehensive Loss		(619,755	)		(640,504	)
Common Stock in Treasury, at Cost—1,486,567 Shares at September 30, 2010 and 1,928,159 Shares at December 31, 2009		(53,164	)		(66,292	)
Total CONSOL Energy Inc. Stockholders’ Equity		3,106,282			1,785,548
Noncontrolling Interest		(8,653	)		238,931
TOTAL EQUITY		3,097,629			2,024,479
TOTAL LIABILITIES AND EQUITY	$	11,721,758		$	7,775,401

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

5

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		—		—			242,320			—			—			242,320			11,845			254,165
Treasury Rate Lock (Net of $37 Tax)		—		—			—			(64	)		—			(64	)		—			(64	)
Gas Cash Flow Hedge (Net of $3,713 Tax)		—		—			—			(11,052	)		—			(11,052	)		5,252			(5,800	)
Actuarially Determined Long-Term Liability Adjustments (Net of $8,627 Tax)		—		—			—			13,839			—			13,839			5			13,844
Purchase of CNX Gas Noncontrolling Interest		—		—			—			18,026			—			18,026			—			18,026
Comprehensive Income		—		—			242,320			20,749			—			263,069			17,102			280,171
Issuance of Treasury Stock		—		—			(18,173	)		—			13,128			(5,045	)		—			(5,045	)
Issuance of Common Stock		443		1,828,419			—			—			—			1,828,862			—			1,828,862
Issuance of CNX Gas Stock		—		—			—			—			—			—			2,178			2,178
Purchase of CNX Gas Noncontrolling Interest		—		(746,052	)		—			—			—			(746,052	)		(263,008	)		(1,009,060	)
Tax Benefit From Stock-Based Compensation		—		9,668			—			—			—			9,668			—			9,668
Stock-Based Compensation Awards to CNX Gas		—		2,126			—			—			—			2,126			(1,771	)		355
Amortization of Stock-Based Compensation Awards		—		31,382			—			—			—			31,382			2,198			33,580
Net Change in Crown Drilling Noncontrolling Interest		—		—			—			—			—			—			(4,283	)		(4,283	)
Dividends ($0.30 per share)		—		—			(63,276	)		—			—			(63,276	)		—			(63,276	)
Balance at September 30, 2010	$	2,273	$	2,159,159		$	1,617,769		$	(619,755	)	$	(53,164	)	$	3,106,282		$	(8,653	)	$	3,097,629

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

6

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended September 30,
	2010			2009
Operating Activities:
Net Income	$	254,165		$	417,096
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		413,379			323,659
Stock-Based Compensation		33,580			30,873
Gain on Sale of Assets		(8,475	)		(13,033	)
Amortization of Mineral Leases		3,890			3,444
Deferred Income Taxes		3,372			51,507
Equity in Earnings of Affiliates		(15,595	)		(12,488	)
Changes in Operating Assets:
Accounts and Notes Receivable		(66,840	)		115,212
Inventories		45,126			(82,729	)
Prepaid Expenses		(26,216	)		(9,826	)
Changes in Other Assets		23,764			799
Changes in Operating Liabilities:
Accounts Payable		63,168			(80,546	)
Other Operating Liabilities		109,371			5,275
Changes in Other Liabilities		14,051			(35,594	)
Other		32,190			14,559
Net Cash Provided by Operating Activities		878,930			728,208
Investing Activities:
Capital Expenditures		(821,908	)		(689,119	)
Acquisition of Dominion Exploration and Production Business		(3,474,199	)		—
Purchase of CNX Gas Noncontrolling Interest		(991,034	)		—
Proceeds from Sales of Assets		24,944			70,415
Net Investment in Equity Affiliates		6,867			3,760
Net Cash Used in Investing Activities		(5,255,330	)		(614,944	)
Financing Activities:
Payments on Short-Term Borrowings		(258,950	)		(147,750	)
Payments on Miscellaneous Borrowings		(8,564	)		(16,443	)
Proceeds from Securitization Facility		150,000			—
Proceeds from Issuance of Long-Term Notes		2,750,000			—
Tax Benefit from Stock-Based Compensation		9,926			391
Dividends Paid		(63,276	)		(54,207	)
Proceeds from Issuance of Common Stock		1,828,862			—
Issuance of Treasury Stock		2,601			1,135
Debt Issuance and Financing Fees		(84,224	)		—
Noncontrolling Interest Member Distribution		—			(2,500	)
Net Cash Provided By (Used in) Financing Activities		4,326,375			(219,374	)
Net Decrease in Cash and Cash Equivalents		(50,025	)		(106,110	)
Cash and Cash Equivalents at Beginning of Period		65,607			138,512
Cash and Cash Equivalents at End of Period	$	15,582		$	32,402

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

7

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 and nine months ended September 30, 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 exhibit 99.1 of CONSOL Energy’s Form 8-K filed on September 21, 2010.

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 April 30, 2010.

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 September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Anti-Dilutive Options		819,189		447,333		819,189		1,650,125
Anti-Dilutive Restricted Stock Units		—		—		1,960		5,344
Anti-Dilutive Performance Stock Units		—		36,352		—		36,352
		819,189		483,685		821,149		1,691,821

Options exercised during the three months ended September 30, 2010 and 2009 were 23,562 shares and 23,958 shares, respectively. The weighted average exercise price per share of the options exercised during the three months ended September 30, 2010 and 2009 was $16.01 and $21.76, respectively. There were 26,562 and 116,800 fully vested restricted stock awards released during the three months ended September 30, 2010 and 2009, respectively.

Options exercised during the nine months ended September 30, 2010 and 2009 were 146,555 shares and 81,045 shares, respectively. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2010 and 2009 was $17.69 and $14.66, respectively. There were 450,891 and

8

198,472 fully vested restricted stock awards released during the nine months ended September 30, 2010 and 2009, respectively.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net income attributable to CONSOL Energy Inc. shareholders	$	75,383	$	87,370	$	242,320	$	396,528
Weighted average shares of common stock outstanding:
Basic		225,781,539		180,725,194		211,235,893		180,649,268
Effect of stock-based compensation awards		2,310,760		2,466,473		2,402,283		2,102,654
Dilutive		228,092,299		183,191,667		213,638,176		182,751,922
Earnings per share:
Basic	$	0.33	$	0.48	$	1.15	$	2.20
Dilutive	$	0.33	$	0.48	$	1.13	$	2.17

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

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In September 2010, CONSOL Energy completed a sale-leaseback of longwall shields for Enlow Fork. Cash proceeds from the sale were $14,551, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In June 2010, CONSOL Energy paid Yukon Pocahontas Coal Company $30,000 cash to acquire certain coal reserves and $20,000 cash in advanced royalty payments as per the settlement referenced in Note 11 – “Commitments and Contingencies.”

On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas Corporation (CNX Gas) outstanding common stock for a cash payment of $966,811 pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. All of the shares of CNX Gas that were not already owned by CONSOL Energy were acquired at a price of $38.25. CONSOL Energy previously owned approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. An additional $24,223 cash payment was made to cancel previously vested CNX Gas stock options. CONSOL Energy financed the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and proceeds from its offering of common stock.

On April 30, 2010, CONSOL Energy completed the Dominion Acquisition for a cash payment of $3,474,199, which was principally allocated to oil and gas properties, wells and well related equipment. The acquisition, which was accounted for under the Business Combination Topic of the FASB Accounting Standards Codification, includes approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 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

9

Pennsylvania and northern West Virginia. Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition is expected to enhance CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.

The following table summarizes the preliminary estimates of the fair value of identifiable assets acquired and liabilities assumed as of the date of the acquisition. CONSOL Energy continues to evaluate assets acquired and liabilities assumed which may result in adjustments to the preliminary values presented below.

	Preliminary Estimates of Acquisition Date Fair Value
Assets
Current Assets:
Inventory	$	301
Prepaid Expenses		2,480
Total Current Assets		2,781
Property, plant and equipment		3,540,683
Total Assets	$	3,543,464
Liabilities
Current Liabilities:
Other Accrued Liabilities	$	24,994
Deferred Credits and Other Liabilities:
Gas Well Closing		35,290
Postretirement Benefits Other Than Pension		2,800
Salary Retirement		900
Other		5,281
Total Deferred Credits and Other Liabilities		44,271
Total Liabilities	$	69,265
Net Assets Acquired	$	3,474,199

The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of May 1, 2010. Net revenues resulting from the Dominion Acquisition that were included in CONSOL Energy’s operating results were $53,463 and $86,857, respectively, for the three and nine months ended September 30, 2010. Net income (loss) resulting from the Dominion Acquisition that was included in CONSOL Energy’s operating results was $(3,370) and $(2,518), respectively, for the three and nine months ended September 30, 2010.

The unaudited pro forma results for the periods presented below are prepared as if the transaction occurred at the beginning of each period presented. Pro forma adjustments include estimated operating results, additional interest related to the $2,750,000 of senior unsecured notes and 44,275,000 shares of common stock issued in connection with the transaction.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Total Revenue and Other Income	$	1,349,293	$	1,129,826	$	3,945,720	$	3,506,135
Earnings Before Income Taxes	$	91,140	$	65,064	$	276,044	$	397,381
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	75,383	$	42,608	$	203,660	$	263,526
Basic Earnings Per Share	$	0.33	$	0.19	$	0.90	$	1.17
Dilutive Earnings Per Share	$	0.33	$	0.19	$	0.89	$	1.16

10

The pro forma results are not necessarily indicative of what actually would have occurred if the Dominion Acquisition had been completed as of the beginning of each fiscal period presented, nor are they necessarily indicative of future consolidated results.

In 2010, CONSOL Energy incurred $337 and $64,415 of acquisition-related costs as a direct result of the Dominion Acquisition and purchase of CNX Gas Noncontrolling Interest in the three and nine months ended September 30, 2010, respectively. These expenses have been included within Acquisition and Financing Fees on the Consolidated Statements of Income for the period ended September 30, 2010.

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 $10,482 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.

In August 2009, CONSOL Energy completed the lease assignment of a subsidiary’s previous headquarters. Total expense related to this transaction for the three and nine months ended September 30, 2009 was $676 and $1,500, respectively, which was recognized in Cost of Goods Sold and Other Operating Charges.

In August 2009, CONSOL Energy completed a sale-leaseback of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In July 2009, CONSOL Energy, through a subsidiary, leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price for the transaction was principally allocated to gas properties and related development.

In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $11,848 in accordance with the Exit or Disposal Cost Obligations Topic of the FASB Accounting Standards Codification related to the Company’s previous headquarters. This liability was recorded in Other Liabilities on the consolidated balance sheet at June 30, 2009. Total expense related to this transaction was $13,374 which was recognized in Cost of Goods Sold and Other Operating Charges. This amount included the fair value of the remaining lease payments of $11,848 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005.

11

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

Components of net periodic costs for the three and nine months ended September 30 are as follows:

	Pension Benefits												Other Benefits
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost	$	3,644		$	3,193		$	10,857		$	9,362		$	3,303		$	3,163		$	9,843		$	9,490
Interest cost		9,311			8,918			27,908			26,659			40,725			37,862			122,091			113,588
Expected return on plan assets		(9,262	)		(9,203	)		(27,786	)		(27,518	)		—			—			—			—
Amortization of prior service (credits)		(184	)		(277	)		(551	)		(831	)		(11,604	)		(11,604	)		(34,811	)		(34,811	)
Recognized net actuarial loss		7,968			5,566			23,903			16,697			17,537			12,590			52,609			37,768
Net periodic benefit cost	$	11,477		$	8,197		$	34,331		$	24,369		$	49,961		$	42,011		$	149,732		$	126,035

For the nine months ended September 30, 2010, $56,286 in contributions were paid to the pension trust and to pension benefits from operating cash flows. CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $71,600 to the 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 nine months ended September 30, 2010, $119,847 of other postemployment benefits have been paid.

The Dominion Acquisition resulted in an initial increase of $900 and $2,800 in the pension and other postretirement liabilities, respectively. The acquisition did not significantly increase net periodic benefit costs in the three or nine months ended September 30, 2010.

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

Components of net periodic costs (benefits) for the three and nine months ended September 30 are as follows:

	CWP												Workers’ Compensation
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost	$	1,040		$	1,769		$	4,027		$	5,306		$	6,754		$	7,099		$	20,262		$	21,296
Interest cost		2,681			3,014			8,108			9,041			2,289			2,191			6,867			6,573
Amortization of actuarial gain		(5,777	)		(5,080	)		(16,536	)		(15,239	)		(768	)		(1,050	)		(2,304	)		(3,150	)
State administrative fees and insurance bond premiums		—			—			—			—			2,020			1,586			6,238			5,138
Legal and administrative costs		750			675			2,250			2,025			785			850			2,354			2,551
Net periodic cost (benefit)	$	(1,306	)	$	378		$	(2,151	)	$	1,133		$	11,080		$	10,676		$	33,417		$	32,408

The CWP liability was remeasured as of April 1, 2010 due to new legislation enacted in the Patient Protection and Affordable Care Act (PPACA). In general, the PPACA impacts CONSOL Energy’s liability in that future claims will be approved at a higher rate than has occurred in the past. The PPACA made two changes to the Federal Black Lung Benefits Act (FBLBA). First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mines and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused at his/her work. Second, it changed the law so that black lung benefits being received by miners automatically go to their dependent survivors, regardless of cause of the miner’s death. The impact of the new law increased CONSOL Energy’s CWP liability by $45,700. The law change increased expense by $2,219 and $4,438 for the three and nine months ended September 30, 2010, respectively. In conjunction with the law change, CONSOL Energy conducted an extensive experience study regarding the rate of claim incidence. Based on historical company data and available industry data, with emphasis on recent history, certain assumptions were revised at the remeasurement date. Most notably, the expected number of claims, prior to the law change, was reduced to more appropriately reflect CONSOL Energy’s historical experience. The assumption and remeasurement changes resulted in a decrease in the liability of $47,700. The assumption and remeasurement changes reduced expense by $3,525 and $7,050 for the three and nine months ended September 30, 2010, respectively.

The combined impact of the changes in actuarial assumptions, remeasurement and changes to the FBLBA was a net decrease of $2,000 in liability as well as Accumulated Other Comprehensive Income based on an April 1, 2010 remeasurement date. The combined impact of these changes reduced expense by $1,306 and $2,612 for the three and nine months ended September 30, 2010, respectively.

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 nine months ended September 30, 2010, $8,949 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 nine months ended September 30, 2010, $27,367 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

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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 Nine Months Ended September 30,
	2010						2009
	Amount			Percent			Amount			Percent
Statutory U.S. federal income tax rate	$	115,310			35.0	%	$	205,263			35.0	%
Excess tax depletion		(49,852	)		(15.1	)		(52,313	)		(8.9	)
Effect of Domestic Production Activities Deduction		(4,916	)		(1.5	)		(8,152	)		(1.4	)
Effect of Federal Tax Accrual to Tax Return Reconciling Adjustment		3,163			1.0			598			0.1
Net effect of state income taxes		9,220			2.8			20,820			3.6
Other		2,366			0.7			3,154			0.5
Income Tax Expense / Effective Rate	$	75,291			22.9	%	$	169,370			28.9	%

The effective rate for the nine months ended September 30, 2010 and 2009 was calculated using the annual effective rate projection on recurring earnings and includes tax liabilities related to certain discrete transactions as described below.

CONSOL Energy was advised by the Canadian Revenue Agency and various 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 $3,424 as a discrete reduction to foreign income tax expense in the nine months ended September 30, 2010. Accordingly, a discrete federal income tax expense of $1,445 was also recognized related to this transaction.

As a result of the Dominion Acquisition, CONSOL Energy recognized a discrete state income tax expense of $1,782 due to the impact of the acquisition on existing deferred tax assets and liabilities. Accordingly, a discrete reduction to federal income tax expense of $624 was also recognized related to this transaction.

CONSOL Energy was notified by the state of Ohio that the state had completed its audit of the Company’s net operating loss (NOL) carryovers. In 2010, Ohio completed a transition from an income and franchise tax to a Commercial Activities Tax (CAT). The state’s audit concluded that CONSOL Energy is entitled to a credit for unused NOLs against future CAT liabilities. These NOLs were previously fully reserved. CONSOL Energy recognized a discrete reduction to state income tax expense of $2,068 related to the reversal of the previously recognized NOL allowance based on the audit settlement.

The total amounts of uncertain tax positions at September 30, 2010 and 2009 were $56,916 and $44,980, respectively. If these uncertain tax positions 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 uncertain tax positions during the nine months ended September 30, 2010 and 2009. In the next twelve month period, the Company expects to reduce its total uncertain tax positions at September 30, 2010 by $22,807 due to audit settlements and expiration of statutes of limitation.

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 is currently at the appeals level of exam for its U.S. federal income tax returns for tax years 2004 and 2005. The Company anticipates that the appeal will be resolved within the next twelve months. The Company filed refund claims related to its Extraterritorial Income Exclusion that, if successfully resolved, could result in tax refunds for 2004 and 2005 of $615 and $608, respectively.

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CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of September 30, 2010 and 2009, the Company reported an accrued interest liability relating to uncertain tax positions of $10,578 and $7,014, respectively. The accrued interest liability includes $2,240 and $1,085 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2010 and 2009, respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 30, 2010 and 2009, CONSOL Energy had no accrued liability for tax penalties.

NOTE 6—INVENTORIES:

Inventory components consist of the following:

	September 30, 2010		December 31, 2009
Coal.	$	115,626	$	173,719
Merchandise for resale.		49,127		44,842
Supplies.		97,578		89,036
Total Inventories.	$	262,331	$	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 $17,476 and $13,696 at September 30, 2010 and December 31, 2009, respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

In April 2010, CONSOL Energy and certain of our U.S. subsidiaries amended their existing trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The amended facility allows CONSOL Energy to receive on a revolving basis up to $200,000, a $35,000 increase over the previous facility. The amended facility also allows for the issuance of letters of credit against the $200,000 capacity. At September 30, 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 Sheet, 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 nine months ended September 30, 2010 classifications required by the Transfers and Servicing Topic of the FASB Accounting Standards Codification.

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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 $863 and $1,868 for the three and nine months ended September 30, 2010, respectively. Costs associated with the receivables facility totaled $705 and $2,474 for the three and nine months ended September 30, 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 September 30, 2010 and December 31, 2009, eligible accounts receivable totaled $200,000 and $151,000 respectively. There was no subordinated retained interest at September 30, 2010. There was subordinated retained interest of $101,000 at December 31, 2009. Accounts Receivable – Securitization and Borrowings under Securitization Facility of $200,000 and $50,000 were recorded on the Consolidated Balance Sheet at September 30, 2010 and December 31, 2009, respectively. Also, the $150,000 increase in the accounts receivable securitization program for the nine months ended September 30, 2010 is reflected in the net cash provided by financing activities in the Consolidated Statement of Cash Flows. There was no change in the facility usage in the nine months ended September 30, 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.

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:

	September 30, 2010		December 31, 2009
Coal & other plant and equipment	$	5,006,253	$	4,874,880
Unproven gas properties		2,194,227		271,125
Proven gas properties		1,656,178		199,074
Coal properties and surface lands		1,316,043		1,284,795
Intangible drilling cost		1,054,100		913,231
Gas gathering equipment		916,775		804,212
Airshafts		652,082		622,068
Mine development		592,476		573,037
Leased coal lands		504,334		504,475
Coal advance mining royalties		390,862		366,312
Gas wells and related equipment		379,728		253,833
Other gas assets		71,375		12,213
Gas advance royalties		3,357		2,700
Total property, plant and equipment		14,737,790		10,681,955
Less Accumulated depreciation, depletion and amortization		4,747,384		4,557,665
Total Net Property, Plant and Equipment	$	9,990,406	$	6,124,290

In September 2010, CONSOL Energy incurred $13,602 of expense relating to the abandonment of a portion of the Mine 84 developed underground area. This abandonment occurred due to a change in the future mine plan, in which this developed area was permanently sealed. Costs related to develop this portion of the mine were previously capitalized, therefore, depreciation, depletion and amortization was accelerated. The expenses related to the abandonment were captured in Depreciation, Depletion and Amortization on the Consolidated Income Statement, and are reflected in the Other Coal segment.

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NOTE 9—SHORT-TERM NOTES PAYABLE:

On May 7, 2010, CONSOL Energy entered into a four-year $1,500,000 senior secured credit facility, which extends through May 7, 2014. It replaced a five-year $1,000,000 senior secured facility which extended through June 2012. The new 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 2.00 to 1.00, measured quarterly. The interest coverage ratio was 5.80 to 1.00 at September 30, 2010. The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The leverage ratio was 3.73 to 1.00 at September 30, 2010. The facility also includes a senior secured leverage ratio covenant of not more than 2.50 to 1.00, measured quarterly. The senior secured leverage ratio was 0.75 to 1.00 at September 30, 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, merge with another corporation and amend, modify or restate the senior unsecured or secured notes. At September 30, 2010, the $1,500,000 facility had $136,000 of borrowings outstanding and $267,999 of letters of credit outstanding, leaving $1,096,001 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 3.76% as of September 30, 2010. Accrued interest of $181 and $51 is included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2010 and December 31, 2009, respectively.

CNX Gas has a four-year $700,000 senior secured credit agreement effective May 7, 2010, which extends through May 6, 2014. It replaced a five-year $200,000 unsecured credit agreement that extended through October 2010. The new facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. Effective June 30, 2010, the assets acquired in the Dominion Acquisition have been merged into one entity and the shares of this entity have been transferred to CNX Gas, making it a wholly-owned subsidiary of CNX Gas. The acquired assets are now pledged as collateral under the CNX Gas senior secured credit agreement. 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 the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.28 to 1.00 at September 30, 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 86.67 to 1.00 at September 30, 2010. At September 30, 2010, the $700,000 facility had $77,900 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $607,187 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 2.36% as of September 30, 2010. Accrued interest of $135 and $22 is included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2010 and December 31, 2009, respectively.

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NOTE 10—LONG-TERM DEBT:

	September 30, 2010		December 31, 2009
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	—
Senior notes due April 2020 at 8.25%, issued at par value		1,250,000		—
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $293 and $447 at September 30, 2010 and December 31, 2009, respectively)		249,707		249,553
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%		102,865		—
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%		—		30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%		—		72,000
Advance royalty commitments (7.36% weighted average interest rate for September 30, 2010 and December 31, 2009)		35,176		35,547
Note due December 2012 at 6.10%		11,218		14,628
Other long-term notes maturing at various dates through 2031 (total value of $148 and $164 less unamortized discount of $1 and $4 at September 30, 2010 and December 31, 2009, respectively)		147		160
		3,149,113		402,753
Less amounts due in one year		8,349		39,024
Long-Term Debt	$	3,140,764	$	363,729

In September 2010, CONSOL Energy refinanced $102,865 of industrial development bonds associated with its wholly-owned CNX Marine Terminal in the Port of Baltimore, Maryland. The refunding municipal bonds issued by the Maryland Economic Development Corporation mature on September 1, 2025 and carry an interest rate of 5.75%. The previous bonds carried an interest rate of 6.50% and were due to mature in December 2010 and October 2011.

Accrued interest related to Long-Term Debt of $113,387 and $8,080 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2010 and December 31, 2009, respectively.

NOTE 11—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 resource 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 resource 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

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by subsidence. On February 16, 2010, DEP issued its interim report, concluding that the alleged damage was subsidence related. The Commonwealth and the Company are now in 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 defend 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, Texas 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 that CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $64,000. The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $11,000. 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 cost of goods sold and other charges in the three months ended September 30, 2010. There was $2,880 of expense recognized in cost of goods sold and other charges in the nine months ended September 30, 2010. There was $1,024 and $4,480 of expense recognized in cost of goods sold for the three and nine months ended September 30, 2009, respectively. CONSOL Energy funded $1,209 and $5,500 in the nine months ended September 30, 2010 and 2009, respectively, to an independent trust established for this remediation. The remaining liability at September 30, 2010 of $7,587 is reflected in Other Accrued Liabilities.

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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 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 were 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, and to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group also filed a demand for arbitration (the “2008 Arbitration”) against ICCC which made similar claims relating to breach of the lease for water deposits and lost coal claims. All of the foregoing claims have been settled through a $75,000 cash payment made to the plaintiffs. The payment represented $25,000 of damages, which was recognized in the nine months ended September 30, 2010, and $50,000 for the purchase of coal reserves and an advance mining royalty on leased coal reserves.

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. As a result of the settlement with the Yukon group, the Yukon group withdrew its appeal.

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.

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 now scheduled for the week of January 31, 2011. 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

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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. 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, pipelines to convey mine water from CCC’s mines to the centralized plant and a landfill for solid waste generated by the plant may reach or exceed $200,000. 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 WVDEP. The December 18, 2009 WVDEP unilateral Order was replaced by another unilateral Order that became effective on April 30, 2010 and will extend until October 31, 2010, or until replaced by the joint WVDEP/EPA consent decree that is being negotiated. 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 tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did 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. The Delaware Court of Chancery denied an injunction against the tender offer and CONSOL Energy acquired all of the outstanding shares of CNX Gas. The Delaware Court of Chancery certified to the Delaware Supreme Court the question of what standard should be applied to the tender offer, which would determine whether the shareholders can proceed with a damage claim. The Delaware Supreme Court declined to accept the appeal pending a final judgment. Therefore, the lawsuit will likely go through a fact discovery phase and, later, trial. 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.

A class action lawsuit was filed in U.S. District Court for the Southern District of Mississippi styled Comer v. CONSOL Energy, et.al. on April 21, 2006. The suit names a multitude of energy producers, chemical manufacturers, and public utilities as defendants. The action is a claim for the enhanced damages suffered in Hurricane Katrina allegedly due to global warming caused by defendants’ supposed contribution to greenhouse gases. The trial court dismissed the case and plaintiffs appealed. The appellate court reversed and the defendants sought rehearing en banc. Rehearing en banc was granted, but a number of judges recused themselves and there was no longer a quorum. As a result, the trial court’s dismissal was reinstated. The Plaintiffs are seeking a Writ of Mandamus from the U.S. Supreme Court. Until the Supreme Court decides the appeal, it is not possible to

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evaluate the likelihood of an unfavorable outcome or to estimate the range of potential loss. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. We cannot predict the ultimate outcome, however, if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations and cash flows of CONSOL Energy.

A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, VA styled Hale v. CNX Gas Company LLC et. al. The lawsuit alleges that the plaintiff class consists of oil and gas owners, that the Virginia Supreme Court has decided that coalbed methane (CBM) belongs to the owner of the oil and gas estate, that the Virginia Gas and Oil Act of 1990 unconstitutionally allows forced pooling of CBM, that the Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the forced pooling orders, and that the Company only relied upon control of the coal estate in force pooling the CBM notwithstanding the Virginia Supreme Court decision holding that if only the coal estate is controlled, the CBM is not thereby controlled. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production, i.e. the 1/8 royalty and the 7/8 of net revenues since production began, be distributed to the class members. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. We cannot predict the outcome, however, if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations and 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 has increased. Changes in mining plans have increased the quantity of material required to reclaim the disturbed area. A detailed reclamation plan has been developed and the definitive costs associated with the increased reclamation have been estimated. As a result, $28,178 of expense was recognized in the three months ended September 30, 2010 and $80,178 of expense was recognized in the nine months ended September 30, 2010.

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. Both Plaintiffs and CNX Gas filed and argued motions for summary judgment; a decision on the motions has not been issued. 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, if damages or other relief were awarded to Plaintiffs, the result 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

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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 September 30, 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	$	198,923	$	139,885	$	59,038	$	—	$	—
Environmental		57,385		55,657		1,728		—		—
Gas		14,913		14,913		—		—		—
Other		11,764		11,700		64		—		—
Total Letters of Credit		282,985		222,155		60,830		—		—
Surety Bonds:
Employee-Related		196,350		196,350		—		—		—
Environmental		371,263		369,440		1,823		—		—
Gas		6,856		6,716		139		—		1
Other		6,092		5,910		182		—		—
Total Surety Bonds		580,561		578,416		2,144		—		1
Guarantees:
Coal		188,868		138,971		43,748		1,149		5,000
Gas		68,151		42,563		22,488		—		3,100
Other		410,428		75,609		116,551		79,352		138,916
Total Guarantees		667,447		257,143		182,787		80,501		147,016
Total Commitments	$	1,530,993	$	1,057,714	$	245,761	$	80,501	$	147,017

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 extended to support insurance policies, legal matters and various other items necessary in the normal course of business. Other guarantees have also been provided to promise the full and timely payments to lessors of mining equipment and support various other items necessary in the normal course of business.

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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 September 30, 2010, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due	Amount
Less than 1 year	$	173,326
1 - 3 years		295,257
3 - 5 years		92,117
More than 5 years		318,960
Total Purchase Obligations	$	879,660

Costs related to these purchase obligations include:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Major equipment purchases	$	10,687	$	8,436	$	37,835	$	77,488
Firm transportation expense		9,021		5,562		25,124		15,281
Gas drilling obligations		5,934		—		6,564		—
Other		195		30		400		90
Total costs related to purchase obligations	$	25,837	$	14,028	$	69,923	$	92,859

NOTE 12—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 period. 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. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodity. As of September 30, 2010, the total notional amount of the Company’s outstanding natural gas swap contracts was 49.6 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $41,687 of unrealized gain is expected to be reclassified from Other

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Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of September 30, 2010, CONSOL Energy did not have any outstanding coal sales options. For the three and nine months ended September 30, 2009, CONSOL Energy recognized, in Other Income on the Consolidated Statements of Income, a gain of $30 and $2,368, respectively, for the coal sales options which were not designated as hedging instruments.

The fair value of CONSOL Energy’s derivative instruments at September 30, 2010 is as follows:

	Derivatives As of September 30, 2010
	Balance Sheet Location		Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps		Prepaid Expense	$	68,649
Natural Gas Price Swaps		Other Assets		39,372
Total derivatives designated as hedging instruments			$	108,021

The effect of derivative instruments on the Consolidated Statements of Income for the three months ended September 30, 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	$	43,367		Outside Sales	$	40,711		Outside Sales	$	(98	)
Total	$	43,367			$	40,711			$	(98	)

The effect of derivative instruments on the Consolidated Statements of Income for the nine months ended September 30, 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 Gain Recognized in Income on Derivative		Amount of Gain Recognized in Income on Derivative 2010
Natural Gas Price Swaps	$	132,895		Outside Sales	$	138,645		Outside Sales	$	50
Total	$	132,895			$	138,645			$	50

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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 Statements of Income for the three months ended September 30, 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	$	27,907		Outside Sales	$	68,804		Outside Sales	$	(63	)
Total	$	27,907			$	68,804			$	(63	)

The effect of derivative instruments on the Consolidated Statements of Income for the nine months ended September 30, 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	$	137,247		Outside Sales	$	185,542		Outside Sales	$	(932	)
Total	$	137,247			$	185,542			$	(932	)

NOTE 13—OTHER COMPREHENSIVE LOSS:

Total comprehensive income (loss), net of tax, for the nine months ended September 30, 2010 is 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		$	(699,293	)	$	(12,769	)	$	(640,504	)
Net increase in value of cash flow hedges		–			132,895			–			(12,500	)		120,395
Reclassification of cash flow hedges from other comprehensive income to earnings		–			(138,695	)		–			7,248			(131,447	)
Elimination of noncontrolling interest from purchase of CNX Gas		–			–			–			18,026			18,026
Current period change		(64	)		–			13,844			(5	)		13,775
Balance at September 30, 2010	$	116		$	65,578		$	(685,449	)	$	—		$	(619,755	)

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NOTE 14—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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

	Fair Value Measurements at September 30, 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	$	—	$	108,021	$	—

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.

Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility 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:

	September 30, 2010						December 31, 2009
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	15,582		$	15,582		$	65,607		$	65,607
Short-term notes payable	$	(213,900	)	$	(213,900	)	$	(472,850	)	$	(472,850	)
Borrowings under Securitization Facility	$	(200,000	)	$	(200,000	)	$	(50,000	)	$	(50,000	)
Long-term debt	$	(3,149,113	)	$	(3,397,373	)	$	(402,753	)	$	(420,056	)

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NOTE 15—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 nine months ended September 30, 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 nine months ended September 30, 2010, the Low Volatile Metallurgical aggregated segment includes the Buchanan mine. For the nine months ended September 30, 2010, the High Volatile Metallurgical aggregated segment includes: Bailey, Enlow Fork, Fola Complex and Emery coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, 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, 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. These reclassifications include changes to the Coal operating segments and the addition of the Gas operating segments.

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Industry segment results for three months ended September 30, 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	$	740,611	$	215,394	$	22,208	$	3,338		$	981,551	$	140,801	$	15,224	$	45,212		$	2,365		$	203,602	$	75,346	$	—		$	1,260,499
Sales—Purchased Gas		—		—		—		—			—		—		—		—			3,524			3,524		—		—			3,524
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—			18,131			18,131		—		—			18,131
Freight—outside		—		—		—		37,269			37,269		—		—		—			—			—		—		—			37,269
Intersegment transfers		—		—		—		—			—		—		—		—			851			851		42,359		(43,210	)		—
Total Sales and Freight	$	740,611	$	215,394	$	22,208	$	40,607		$	1,018,820	$	140,801	$	15,224	$	45,212		$	24,871		$	226,108	$	117,705	$	(43,210	)	$	1,319,423
Earnings (Loss) Before Income Taxes	$	85,085	$	135,171	$	11,599	$	(113,272	)	$	118,583	$	59,257	$	2,332	$	(2,420	)	$	(23,646	)	$	35,523	$	8,853	$	(71,819	)	$	91,140	(A)
Segment assets										$	4,948,966											$	5,868,941	$	324,638	$	579,213		$	11,721,758	(B)
Depreciation, depletion and amortization										$	98,101											$	58,909	$	4,419	$	—		$	161,429
Capital expenditures										$	132,847											$	102,235	$	7,735	$	—		$	242,817

(A) Includes equity in earnings of unconsolidated affiliates of $4,142, $785 and $1,976 for Coal, Gas and All Other, respectively.

(B) Includes investments in unconsolidated equity affiliates of $20,472, $24,651 and $47,138 for Coal, Gas and All Other, respectively.

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Industry segment results for three months ended September 30, 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	$	737,061	$	63,184	$	—		$	163		$	800,408	$	142,231	$	9,269	$	1,617		$	1,219		$	154,336	$	67,873	$	—		$	1,022,617
Sales—Purchased Gas		—		—		—			—			—		—		—		—			1,471			1,471		—		—			1,471
Sales—Gas Royalty Interests		—		—		—			—			—		—		—		—			8,443			8,443		—		—			8,443
Freight—outside		—		—		—			36,130			36,130		—		—		—			—			—		—		—			36,130
Intersegment transfers		—		—		—			—			—		—		—		—			449			449		37,607		(38,056	)		—
Total Sales and Freight	$	737,061	$	63,184	$	—		$	36,293		$	836,538	$	142,231	$	9,269	$	1,617		$	11,582		$	164,699	$	105,480	$	(38,056	)	$	1,068,661
Earnings (Loss) Before Income Taxes	$	141,127	$	28,465	$	(26	)	$	(96,935	)	$	72,631	$	67,946	$	2,809	$	(985	)	$	(12,018	)	$	57,752	$	5,332	$	(7,210	)	$	128,505	(C)
Segment assets											$	4,607,877											$	2,137,337	$	323,230	$	415,493		$	7,483,937	(D)
Depreciation, depletion and amortization											$	73,960											$	30,879	$	5,126	$	—		$	109,965
Capital expenditures											$	140,518											$	49,288	$	2,894	$	—		$	192,700

(C) Includes equity in earnings of unconsolidated affiliates of $1,552, $93 and $4,043 for Coal, Gas and All Other, respectively.

(D) Includes investments in unconsolidated equity affiliates of $11,502, $24,604 and $45,618 for Coal, Gas and All Other, respectively.

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Industry segment results for nine months ended September 30, 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	$	2,202,931	$	490,996	$	135,230	$	32,498		$	2,861,655	$	451,149	$	33,606	$	77,782	$	5,641		$	568,178	$	220,296	$	—		$	3,650,129
Sales—Purchased Gas		—		—		—		—			—		—		—		—		8,280			8,280		—		—			8,280
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—		46,621			46,621		—		—			46,621
Freight—outside		—		—		—		96,544			96,544		—		—		—		—			—		—		—			96,544
Intersegment transfers		—		—		—		—			—		—		—		—		2,413			2,413		129,529		(131,942	)		—
Total Sales and Freight	$	2,202,931	$	490,996	$	135,230	$	129,042		$	2,958,199	$	451,149	$	33,606	$	77,782	$	62,955		$	625,492	$	349,825	$	(131,942	)	$	3,801,574
Earnings (Loss) Before Income Taxes	$	379,559	$	268,547	$	70,563	$	(369,501	)	$	349,168	$	211,179	$	4,694	$	824	$	(53,296	)	$	163,401	$	18,477	$	(201,590	)	$	329,456	(E)
Segment assets										$	4,948,966										$	5,868,941	$	324,638	$	579,213		$	11,721,758	(F)
Depreciation, depletion and amortization										$	259,849										$	139,954	$	13,576	$	—		$	413,379
Capital expenditures										$	517,515										$	3,766,694	$	11,898	$	—		$	4,296,107

(E) Includes equity in earnings of unconsolidated affiliates of $10,570, $60 and $4,965 for Coal, Gas and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $20,472, $24,651 and $47,138 for Coal, Gas and All Other, respectively.

31

Industry segment results for nine months ended September 30, 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	$	2,331,653	$	147,953	$	—		$	21,904		$	2,501,510	$	443,420	$	14,552	$	6,050		$	2,978		$	467,000	$	198,492	$	—		$	3,167,002
Sales—Purchased Gas		—		—		—			—			—		—		—		—			4,102			4,102		—		—			4,102
Sales—Gas Royalty Interests		—		—		—			—			—		—		—		—			29,741			29,741		—		—			29,741
Freight—outside		—		—		—			94,133			94,133		—		—		—			—			—		—		—			94,133
Intersegment transfers		—		—		—			—			—		—		—		—			991			991		112,790		(113,781	)		—
Total Sales and Freight	$	2,331,653	$	147,953	$	—		$	116,037		$	2,595,643	$	443,420	$	14,552	$	6,050		$	37,812		$	501,834	$	311,282	$	(113,781	)	$	3,294,978
Earnings (Loss) Before Income Taxes	$	628,834	$	36,462	$	(26	)	$	(259,950	)	$	405,320	$	227,983	$	2,958	$	(689	)	$	(29,859	)	$	200,393	$	13,539	$	(32,786	)	$	586,466	(G)
Segment assets											$	4,607,877											$	2,137,337	$	323,230	$	415,493		$	7,483,937	(H)
Depreciation, depletion and amortization											$	229,750											$	78,581	$	15,328	$	—		$	323,659
Capital expenditures											$	413,414											$	263,051	$	12,654	$	—		$	689,119

(G) Includes equity in earnings of unconsolidated affiliates of $4,026, $650 and $7,812 for Coal, Gas and All Other, respectively.

(H) Includes investments in unconsolidated equity affiliates of $11,502, $24,604 and $45,618 for Coal, Gas and All Other, respectively.

32

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2010			2009			2010			2009
Segment Earnings Before Income Taxes for total reportable business segments	$	154,106		$	130,383		$	512,569		$	605,713
Segment Earnings Before Income Taxes for all other businesses		8,853			5,332			18,477			13,539
Interest income (expense), net and other non-operating activity (I)		(69,819	)		(7,210	)		(139,092	)		(22,396	)
Acquisition and Financing Fees (I)		(334	)		—			(61,084	)		—
Fees for disposing non-core assets (I)		(1,788	)		—			(1,788	)		—
Operating lease cease-use		122			—			374			(7,543	)
Corporate Restructuring (I)		—			—			—			(2,847	)
Earnings Before Income Taxes	$	91,140		$	128,505		$	329,456		$	586,466

Total Assets:	September 30,
	2010		2009
Segment assets for total reportable business segments	$	10,817,907	$	6,745,214
Segment assets for all other businesses		324,638		323,230
Items excluded from segment assets:
Cash and other investments (I)		14,996		31,943
Recoverable income taxes		27,907		2,643
Deferred tax assets		482,836		380,125
Bond issuance costs		53,474		782
Total Consolidated Assets	$	11,721,758	$	7,483,937

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $250,000, 7.875% per annum notes due March 1, 2012, the $1,500,000, 8.00% per annum notes due April 1, 2017, and the $1,250,000, 8.25% per annum notes due April 1, 2020 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 Guarantor (a guarantor subsidiary), the remaining guarantor subsidiaries and the non-guarantor subsidiaries. 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 wholly 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.

33

Income Statement for the three months ended September 30, 2010 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	204,454	$	1,010,530		$	47,981	$	(2,446	)		1,260,499
Sales—Purchased Gas		—			3,524		—			—		—			3,524
Sales—Gas Royalty Interests		—			18,131		—			—		—			18,131
Freight—Outside		—			—		37,269			—		—			37,269
Other Income (including equity earnings) .		121,067			1,642		18,548			8,455		(119,842	)		29,870
Total Revenue and Other Income		121,067			227,751		1,066,347			56,436		(122,308	)		1,349,293
Cost of Goods Sold and Other Operating Charges		25,292			76,093		682,488			4,228		62,718			850,819
Purchased Gas Costs		—			3,333		—			—		—			3,333
Acquisition and Financing Fees		333			2		2			—		—			337
Gas Royalty Interests’ Costs		—			16,424		—			—		(16	)		16,408
Related Party Activity		(11,119	)		—		(2,901	)		43,601		(29,581	)		—
Freight Expense		—			—		37,269			—		—			37,269
Selling, General and Administrative Expense		—			25,375		34,230			342		(21,225	)		38,722
Depreciation, Depletion and Amortization		2,548			58,909		99,310			662		—			161,429
Interest Expense		61,789			2,154		2,574			6		(93	)		66,430
Taxes Other Than Income		2,352			10,031		70,366			657		—			83,406
Total Costs		81,195			192,321		923,338			49,496		11,803			1,258,153
Earnings (Loss) Before Income Taxes		39,872			35,430		143,009			6,940		(134,111	)		91,140
Income Tax Expense (Benefit)		(35,511	)		14,097		34,545			2,626		—			15,757
Net Income (Loss)		75,383			21,333		108,464			4,314		(134,111	)		75,383
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		—			—
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	75,383		$	21,333	$	108,464		$	4,314	$	(134,111	)		75,383

34

Balance Sheet at September 30, 2010 (unaudited):

	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	9,558	$	1,145		$	3,355		$	1,524	$	—		$	15,582
Accounts and Notes Receivable:
Trade		—		54,948			618			169,675		—			225,241
Securitized		200,000		—			—			—		—			200,000
Other		759		6,996			7,383			4,364		—			19,502
Inventories		1		4,113			209,090			49,127		—			262,331
Recoverable Income Taxes		18,306		9,601			—			—		—			27,907
Deferred Income Taxes		109,347		(22,858	)		—			—		—			86,489
Prepaid Expenses		31,744		75,416			48,325			8,224		—			163,709
Total Current Assets		369,715		129,361			268,771			232,914		—			1,000,761
Property, Plant and Equipment:
Property, Plant and Equipment		164,619		6,229,104			8,318,213			25,854		—			14,737,790
Less-Accumulated Depreciation, Depletion and Amortization		91,236		576,970			4,061,603			17,575		—			4,747,384
Property, Plant and Equipment-Net		73,383		5,652,134			4,256,610			8,279		—			9,990,406
Other Assets:
Deferred Income Taxes		778,705		(382,358	)		—			—		—			396,347
Investment in Affiliates		8,021,305		24,651			949,267			9,891		(8,912,853	)		92,261
Other		144,150		49,290			37,599			10,944		—			241,983
Total Other Assets		8,944,160		(308,417	)		986,866			20,835		(8,912,853	)		730,591
Total Assets	$	9,387,258	$	5,473,078		$	5,512,247		$	262,028	$	(8,912,853	)	$	11,721,758
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	98,199	$	106,431		$	95,351		$	12,929	$	—		$	312,910
Accounts Payable (Recoverable)—Related Parties		2,282,789		(9,879	)		(2,408,476	)		135,566		—			—
Short-Term Notes Payable		136,000		77,900			—			—		—			213,900
Current Portion Long-Term Debt		689		9,443			5,260			525		—			15,917
Borrowings under Securitization Facility		200,000		—			—			—		—			200,000
Other Accrued Liabilities		337,655		64,202			386,006			9,274		—			797,137
Total Current Liabilities		3,055,332		248,097			(1,921,859	)		158,294		—			1,539,864
Long-Term Debt:		3,000,503		60,004			136,769			779		—			3,198,055
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—		7,141			2,679,063			—		—			2,686,204
Pneumoconiosis		—		—			187,049			—		—			187,049
Mine Closing		—		—			391,082			—		—			391,082
Gas Well Closing		—		39,727			70,410			—		—			110,137
Workers’ Compensation		—		—			159,149			38		—			159,187
Salary Retirement		144,677		—			—			—		—			144,677
Reclamation		—		—			70,951			—		—			70,951
Other		80,464		41,949			14,499			11		—			136,923
Total Deferred Credits and Other Liabilities		225,141		88,817			3,572,203			49		—			3,886,210
Total CONSOL Energy Inc. Stockholders’ Equity		3,106,282		5,084,813			3,716,481			102,906		(8,904,200	)		3,106,282
Noncontrolling Interest		—		(8,653	)		8,653			—		(8,653	)		(8,653	)
Total Liabilities and Stockholders’ Equity	$	9,387,258	$	5,473,078		$	5,512,247		$	262,028	$	(8,912,853	)	$	11,721,758

35

Income Statement for the three months ended September 30, 2009 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	154,784	$	819,117		$	49,541	$	(825	)	$	1,022,617
Sales—Purchased Gas		—			1,471		—			—		—			1,471
Sales—Gas Royalty Interests		—			8,443		—			—		—			8,443
Freight—Outside		—			—		36,130			—		—			36,130
Other Income (including equity earnings)		102,002			955		25,433			5,386		(107,920	)		25,856
Total Revenue and Other Income		102,002			165,653		880,680			54,927		(108,745	)		1,094,517
Cost of Goods Sold and Other Operating Charges		15,872			27,952		540,251			48,663		74,518			707,256
Purchased Gas Costs		—			1,103		—			—		—			1,103
Gas Royalty Interests’ Costs		—			6,279		—			—		(11	)		6,268
Related Party Activity		3,331			—		34,123			325		(37,779	)		—
Freight Expense		—			—		36,130			—		—			36,130
Selling, General and Administrative Expense		—			37,600		29,523			311		(35,792	)		31,642
Depreciation, Depletion and Amortization		3,511			30,879		74,919			656		—			109,965
Interest Expense		2,939			1,865		2,783			3		(88	)		7,502
Taxes Other Than Income		1,484			2,549		61,458			655		—			66,146
Total Costs		27,137			108,227		779,187			50,613		848			966,012
Earnings (Loss) Before Income Taxes		74,865			57,426		101,493			4,314		(109,593	)		128,505
Income Tax Expense (Benefit)		(12,505	)		22,194		23,898			1,632		—			35,219
Net Income (Loss)		87,370			35,232		77,595			2,682		(109,593	)		93,286
Less: Net Income Attributable to Noncontrolling Interest		—			238		(238	)		—		(5,916	)		(5,916	)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	87,370		$	35,470	$	77,357		$	2,682	$	(115,509	)	$	87,370

36

Balance Sheet at December 31, 2009:

	Parent Issuer		CNX Gas Guarantor			Other 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
Recoverable Income Taxes		—		—			—			—		—			—
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

37

Income Statement for the Nine Months Ended September 30, 2010 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	570,591	$	2,939,338		$	145,151	$	(4,951	)	$	3,650,129
Sales—Purchased Gas		—			8,280		—			—		—			8,280
Sales—Gas Royalty Interests		—			46,621		—			—		—			46,621
Freight—Outside		—			—		96,544			—		—			96,544
Other Income (including equity earnings)		399,464			3,066		41,033			22,704		(389,141	)		77,126
Total Revenue and Other Income		399,464			628,558		3,076,915			167,855		(394,092	)		3,878,700
Cost of Goods Sold and Other Operating Charges		68,014			184,209		1,996,159			7,255		180,815			2,436,452
Purchased Gas Costs		—			6,980		—			—		—			6,980
Acquisition and Financing Fees		61,083			3,330		2			—		—			64,415
Gas Royalty Interests’ Costs		—			40,182		—			—		(49	)		40,133
Related Party Activity		(12,357	)		—		(7,766	)		132,933		(112,810	)		—
Freight Expense		—			—		96,544			—		—			96,544
Selling, General and Administrative Expense		—			63,067		95,595			982		(51,747	)		107,897
Depreciation, Depletion and Amortization		8,377			139,954		263,046			2,002		—			413,379
Interest Expense		125,787			6,177		7,909			16		(276	)		139,613
Taxes Other Than Income		7,755			21,534		212,404			2,138		—			243,831
Total Costs		258,659			465,433		2,663,893			145,326		15,933			3,549,244
Earnings (Loss) Before Income Taxes		140,805			163,125		413,022			22,529		(410,025	)		329,456
Income Tax Expense (Benefit)		(101,515	)		62,672		105,611			8,523		—			75,291
Net Income (Loss)		242,320			100,453		307,411			14,006		(410,025	)		254,165
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(11,845	)		(11,845	)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	242,320		$	100,453	$	307,411		$	14,006	$	(421,870	)	$	242,320

38

Income Statement for the Nine Months Ended September 30, 2009 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	467,987	$	2,556,568		$	144,707	$	(2,260	)	$	3,167,002
Sales—Purchased Gas		—			4,102		—			—		—			4,102
Sales—Gas Royalty Interests		—			29,741		—			—		—			29,741
Freight—Outside		—			—		94,133			—		—			94,133
Other Income (including equity earnings)		456,966			3,815		64,402			17,017		(453,345	)		88,855
Total Revenue and Other Income		456,966			505,645		2,715,103			161,724		(455,605	)		3,383,833
Cost of Goods Sold and Other Operating Charges		63,211			114,925		1,521,788			140,498		177,313			2,017,735
Purchased Gas Costs		—			3,023		—			—		—			3,023
Gas Royalty Interests’ Costs		—			23,350		—			—		(33	)		23,317
Related Party Activity		6,850			—		95,569			1,112		(103,531	)		—
Freight Expense		—			—		94,133			—		—			94,133
Selling, General and Administrative Expense		—			72,216		88,088			977		(63,197	)		98,084
Depreciation, Depletion and Amortization		10,138			78,581		234,812			1,982		(1,854	)		323,659
Interest Expense		9,911			5,753		7,546			11		(262	)		22,959
Taxes Other Than Income		4,900			8,488		199,066			2,003		—			214,457
Total Costs		95,010			306,336		2,241,002			146,583		8,436			2,797,367
Earnings (Loss) Before Income Taxes		361,956			199,309		474,101			15,141		(464,041	)		586,466
Income Tax Expense (Benefit)		(34,572	)		76,780		121,434			5,728		—			169,370
Net Income (Loss)		396,528			122,529		352,667			9,413		(464,041	)		417,096
Less: Net Income Attributable to Noncontrolling Interest		—			822		(822	)		—		(20,568	)		(20,568	)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	396,528		$	123,351	$	351,845		$	9,413	$	(484,609	)	$	396,528

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Cash Flow for the Nine Months Ended September 30, 2010 (unaudited):

	Parent			CNX Gas Guarantor			Guarantor			Non- Guarantor			Elimination		Consolidated
Net Cash (Used In) Provided by Operating Activities	$	(3,373,370	)	$	267,894		$	3,983,670		$	736		$	—	$	878,930
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(292,495	)	$	(529,413	)	$	—		$	—	$	(821,908	)
Investment in Equity Affiliates		—			—			6,867			—			—		6,867
Acquisition of Dominion		—			—			(3,474,199	)		—			—		(3,474,199	)
Purchase of CNX Gas Noncontrolling Interest		(991,034	)		—			—			—			—		(991,034	)
Other Investing Activities		—			48			24,896			—			—		24,944
Net Cash Used in Investing Activities	$	(991,034	)	$	(292,447	)	$	(3,971,849	)	$	—		$	—	$	(5,255,330	)
Cash Flows from Financial Activities:
Dividends Paid	$	(63,276	)	$	—		$	—		$	—		$	—	$	(63,276	)
Proceeds from Short Term Borrowing		(279,000	)		20,050			—			—			—		(258,950	)
Proceeds on Securitization Facility		150,000			—			—			—			—		150,000
Proceeds from Long Term Notes		2,750,000			—			—			—			—		2,750,000
Proceeds from Issuance of Common Stock		1,828,862			—			—			—			—		1,828,862
Debt Issuance and Financing Fees		(84,224	)		—			—			—			—		(84,224	)
Other Financing Activities		12,051			4,524			(12,230	)		(382	)		—		3,963
Net Cash Provided by (Used in) Financing Activities	$	4,314,413		$	24,574		$	(12,230	)	$	(382	)	$	—	$	4,326,375

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Cash Flow for the Nine Months Ended September 30, 2009 (unaudited):

	Parent			CNX Gas Guarantor			Guarantor			Non- Guarantor			Elimination		Consolidated
Net Cash Provided by (Used in) Operating Activities	$	93,787		$	279,460		$	357,001		$	(2,040	)	$	—	$	728,208
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(273,019	)	$	(416,100	)	$	—		$	—	$	(689,119	)
Investment in Equity Affiliates		—			1,250			2,510			—			—		3,760
Other Investing Activities		—			275			70,140			—			—		70,415
Net Cash Used in Investing Activities	$	—		$	(271,494	)	$	(343,450	)	$	—		$	—	$	(614,944	)
Cash Flows from Financial Activities:
Dividends Paid	$	(54,207	)	$	—		$	—		$	—		$	—	$	(54,207	)
Proceeds from (Payments on) Short Term Borrowing		(148,100	)		350			—			—			—		(147,750	)
Other Financing Activities		1,144			(9,274	)		(8,926	)		(361	)		—		(17,417	)
Net Cash Used in Financing Activities	$	(201,163	)	$	(8,924	)	$	(8,926	)	$	(361	)	$	—	$	(219,374	)

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:

In April 2010, the Financial Accounting Standards Board issued an update to the Extractive Activities – Oil and Gas Topic of the FASB Accounting Standards Codification which is intended to revise definitions due to SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. We believe adoption of this new guidance will not have a material impact on CONSOL Energy’s financial statements.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

Global demand for U.S. metallurgical coal continues to be strong due to worldwide recovery in blast furnace production. U.S. steel mill utilization is currently at 67%, down slightly from 73% six months ago. Through September, global blast furnace iron production is up approximately 19% over 2009 levels and steel mill capacity utilization is currently at 74% in Europe and 85% in China. In the global market, steel demand for the balance of 2010 through 2011 is expected to remain near current levels in Europe and North America due to uncertainty in the global economy. Forecasts for the rate of growth of the Chinese economy remain close to 10% for 2010 and 8.5% for 2011. Given the continued projected growth in the Chinese economy, the shortage of high quality metallurgical coal and relatively low steel inventories, we anticipate metallurgical coal markets will remain strong through 2011.

The thermal coal outlook continues to improve, due to declining inventories and increasing industrial activity. Inventories at utilities in our major market area (Mid Atlantic and South Atlantic markets) are lower than in other regions of the U.S. with inventories at some plants below 30 days of burn as of the end of September. Demand for Northern Appalachian coal continues to be strong, bolstered by both domestic demand and exports to China. Exports of thermal coal are expected to remain strong over the longer term driven by economic growth in developing countries like China, Brazil and India and shifting of traditional coal supplies to meet these growth demands. Regulatory pressures in Central Appalachia continue to increase mining costs and reduce coal supply as permits become increasingly more difficult to obtain. CONSOL Energy estimates that annual production from Central Appalachia will decline another 40 million tons by 2015. The issues in Central Appalachia combined with a general economic recovery are expected to increase coal sales opportunities and expand market share for CONSOL Energy in both the short and long term. CONSOL Energy’s low cost Northern Appalachian mining operations are well positioned to replace production declines in Central Appalachia.

The U.S. natural gas industry continues to face concerns of oversupply, which are holding down gas prices. The supply of natural gas remains very strong due to the success of new shale plays and drilling in these plays to meet drilling commitments. On a positive note, natural gas demand has recovered to pre-recession levels and there are increasing signs of improvement in the gas markets. The summer 2010 cooling season has helped slow storage build compared to 2009 levels. Industrial demand for gas has grown slowly but steadily through 2010. In addition to increases in demand, there have been supply responses to the current price environment. Canadian gas imports have decreased and the expected wave of Liquefied natural gas (LNG) imports has failed to materialize. We expect drilling activity in the shale plays to slow somewhat beginning in late-2011 and beyond as companies adjust their drilling plans in response to the price environment.

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. 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. It is also likely that they will increase the number of inspections at certain coal mines. 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.

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• On September 23, 2010, the Mine Safety and Health Administration (MSHA) published an emergency temporary standard that revises the existing federal standard for the incombustible content of combined coal dust, rock dust and other dust in coal mines. Rock dust is pulverized stone used to cover coal dust and render it inert. Effective rock dust application can prevent coal dust explosions and can reduce the severity of methane explosions. The emergency temporary standard requires mine operators to increase the incombustible content of the combined coal dust, rock dust, and other dust in all accessible areas of underground coal mines to at least 80%. This is an increase from the pre-existing standard of 65%, except for return air courses where the pre-existing standard was already 80%. Mine operators must comply with the standard for newly mined areas by October 7, 2010, and all other areas of the mine by November 22, 2010. To meet these compliance dates, MSHA encouraged mine operators to immediately begin rock dusting all other areas, starting with those that pose the greatest risk to miners: for example, areas near the active faces and areas that contain possible ignition sources, such as conveyer belt drives and belt entries. The new standard will increase costs due to additional rock-dusting materials, additional equipment and additional labor that will be necessary to comply with the new standard.

• Enactment of laws or passage of regulations by the federal government, individual states or other countries regarding emissions from combustion of fossil fuels or establishing renewable energy standards 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 or establishing renewable energy standards, or both, 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. Whether or not climate change legislation is enacted, the U.S. Environmental Protection Agency (EPA) has found that carbon dioxide may reasonably be anticipated to “endanger public health or welfare” (an endangerment finding) under the Clean Air Act and is proposing regulations that would restrict carbon dioxide emissions from certain sources; however, the EPA’s endangerment finding and its authority to adopt such regulations is being challenged in the courts. 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, CONSOL Energy expects gas to be the preferred fuel source for new power plants. Over the long term, CONSOL Energy 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 microSiemens per centimeter in streams below coal mining operations are harmful to aquatic insects and therefore violate state water quality standards. The 500 microSiemens 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,

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it will take longer to obtain NPDES permits and valley fill permits for mining operations, or permit applications may be denied. The guidance has been challenged by the National Mining Association and by the State of West Virginia in separate lawsuits. 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 510 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 11—“Commitments and Contingencies” in Item I, Condensed Consolidated Financial Statements of this Form 10-Q, Consolidation Coal Company (CCC) 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 May 31, 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, pipelines to convey water from CCC’s mines to the centralized plant and a landfill for solid waste generated by the plant may reach or exceed $200 million between now and May 2013. 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. 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 impacted CONSOL Energy’s CWP liability by approximately $46 million, as described more fully in Note 4—“Components of Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation Net Periodic Benefit Costs.”

• On June 29, 2010, EPA included methane emissions from underground coal mines as sources of greenhouse gases subject to the mandatory greenhouse gas reporting regulations that were adopted on October 30, 2009. Under the rule for underground coal mines, any facility that is subject to quarterly sampling for methane of mine ventilation systems by the Mine Safety and Health Administration (MSHA) must begin monitoring methane emissions on January 1, 2011. Reports of methane emissions (and for methane destruction by combustion—carbon dioxide emissions) for 2011 are due to EPA on March 31, 2012. At present the regulations only require monitoring and reporting of the amounts of these emissions from underground coal mines. There are presently no capture or control requirements in the regulations. However, these monitoring and reporting regulations may lead to additional regulation of these emissions from underground coal mines.

• On June 16, 2010, a coalition of environmental groups filed a petition for rulemaking with the EPA asking the EPA to list coal mines as a category of sources that emit air pollution that may reasonably be anticipated to “endanger public health or welfare” (an endangerment finding) and to establish “standards of performance” for emissions of methane, particulate matter, volatile organic compounds and nitrogen oxides from new and modified coal mines. The EPA has 180 days to act on the petition. If the EPA makes an endangerment finding or if it agrees to establish performance standards for methane and other emissions from coal mines, the costs of producing coal could increase significantly making coal less competitive as a source of energy. It is too early to know how the EPA will respond to the petition, but regulation of emissions from coal mines could materially adversely affect our operations and results of operations.

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• In June 2010, the EPA published a proposed rule to regulate coal combustion residuals (coal combustion ash and combustion residuals captured by pollution control devices) under the Resource Conservation and Recovery Act (RCRA). The EPA is co-proposing two regulatory options. The first option is to reverse the EPA’s 1993 and 2000 determinations which concluded that coal combustion residuals should not be regulated as hazardous wastes and instead regulate them as hazardous wastes under Subtitle C of RCRA. The second proposal is to regulate coal combustion residuals under subtitled D of RCRA as non-hazardous wastes. Under either option, disposal of coal combustion residuals will be regulated under RCRA. Regulation as hazardous wastes is likely to be very expensive and regulation as non-hazardous wastes is likely to be more costly than current disposal practices regulated under state laws. In either case it is likely that the regulations will result in increased costs for electricity generated at coal fired facilities making coal fired electricity generation less competitive.

• The EPA has announced that it will conduct a comprehensive study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formations such as the Barnett and Marcellus shales. The study is the result of identification of the need for such a study in the Fiscal Year 2010 budget report of the U. S. House of Representatives Appropriation Conference Committee. The EPA plans to initiate the study in January 2011 and have the initial study results available by late 2012. It is too early to predict what actions, if any, will result from the study.

• In July 2010, financial reform legislation was signed into law. The legislation is designed to prevent financial institutions from gouging consumers on mortgages, credit cards, and other financial products and to provide the government with the tools to avoid further corporate bailouts. The legislation establishes a bureau within the Federal Reserve to protect consumers in the financial markets, creates a body of regulators to monitor the financial system, imposes transparency and accountability standards on complicated financial securities such as derivatives, grants shareholders a nonbinding vote on executive compensation, and provides the government with the power to take over businesses whose failure would damage the economy. The impacts of the legislation on CONSOL Energy may include less availability and higher costs of additional credit and borrowing capacity, increased scrutiny of corporate governance, and added reporting requirements.

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 low-volatile business with our Buchanan coal mine;

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

• Lower 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 believe 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.

In September 2010, CONSOL Energy refinanced approximately $103 million of industrial development bonds associated with its wholly-owned CNX Marine Terminal in the Port of Baltimore, Maryland. The refunding municipal bonds issued by the Maryland Economic Development Corporation mature on September 1, 2025 and carry an interest rate of 5.75%. The previous bonds carried an interest rate of 6.50% and were due to mature in December 2010 and October 2011.

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Results of Operations

Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009

Net Income Attributable to CONSOL Energy

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $75.4 million, or $0.33 per diluted share for the three months ended September 30, 2010. Net income attributable to CONSOL Energy shareholders was $87.4 million, or $0.48 per diluted share, for the three months ended September 30, 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 Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. The aggregate high volatile coal segment includes Bailey, Enlow Fork, 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, as well as various other activities assigned to the coal segment but not allocated to each individual mine.

The average sales price and total costs for all active coal operations was as follows:

	Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Average Sales Price per ton sold	$	63.71	$	58.85	$	4.86		8.3	%
Average Costs per ton sold		48.88		46.49		2.39		5.1	%
Margin	$	14.83	$	12.36	$	2.47		20.0	%

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 average sales price and total costs for all active gas operations was as follows:

	Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	5.72	$	6.25	$	(0.53	)		(8.5	)%
Average Costs per thousand cubic feet sold		4.08		3.44		0.64			18.6	%
Margin	$	1.64	$	2.81	$	(1.17	)		(41.6	)%

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

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TOTAL COAL SEGMENT ANALYSIS for the three months ended September 30, 2010 compared to the three months ended September 30, 2009:

The coal segment contributed $118 million of earnings before income tax in the three months ended September 30, 2010 compared to $72 million in the 2009 period. Variances by the individual coal segments are discussed below.

	For the Three Months Ended September 30, 2010											Difference to Three Months Ended September 30, 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	$	741	$	22	$	215	$	3		$	981	$	4		$	22	$	152	$	3		$	181
Purchased Coal		—		—		—		1			1		—			—		—		1			1
Total Outside Sales		741		22		215		4			982		4			22		152		4			182
Freight Revenue		—		—		—		37			37		—			—		—		1			1
Other Income		1		3		—		18			22		(1	)		3		—		8			10
Total Revenue and Other Income		742		25		215		59			1,041		3			25		152		13			193
Costs and Expenses:
Total operating costs		502		10		62		53			627		49			10		35		(8	)		86
Total provisions		51		1		7		39			98		5			1		4		21			31
Total administrative & other costs		34		—		5		24			63		(2	)		—		3		4			5
Depreciation, depletion and amortization		70		2		6		20			98		7			2		3		12			24
Total Costs and Expenses		657		13		80		136			886		59			13		45		29			146
Freight Expense		—		—		—		37			37		—			—		—		1			1
Total Cost		657		13		80		173			923		59			13		45		30			147
Earnings Before Income Taxes	$	85	$	12	$	135	$	(114	)	$	118	$	(56	)	$	12	$	107	$	(17	)	$	46

STEAM COAL SEGMENT

The steam coal segment contributed $85 million to total company earnings before income tax in the three months ended September 30, 2010 compared to $141 million in the three months ended September 30, 2009.

Steam coal revenue was $741 million in the three months ended September 30, 2010 compared to $737 million in the three months ended September 30, 2009. The $4 million increase was attributable to higher tons sold, partially offset by lower average sales prices received in the period-to-period comparison.

	For the Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		13.7		12.9		0.8			6.2	%
Average Sales Price Per Steam Ton Sold	$	54.02	$	57.05	$	(3.03	)		(5.3	)%

Higher steam tons sold was primarily due to the Shoemaker mine restarting production early in 2010 after being idled throughout the 2009 period. The mine was idled in order to complete the replacement of the track haulage system to a more efficient belt haulage system. Higher steam tons sold was also attributable to a draw down of approximately 0.8 million tons of inventory in the three months ended September 30, 2010 compared to a draw down of approximately 0.1 million tons of inventory in the three months ended September 30, 2009. Produced steam coal inventory was 2.1 million tons at September 30, 2010 compared to 2.8 million tons at

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September 30, 2009. The increased steam tons sold were offset, in part, by 340 thousand tons of steam coal tons sold on the high volatile (vol) metallurgical coal market at approximately $11.36 per ton higher sales price. The steam coal average sales price is lower in the 2010 period as a result of higher average sales price mines, such as Bailey and Enlow Fork, selling coal in the high vol metallurgical coal market. This impacted the steam coal segment due to the proportionately lower tons sold from the higher sales price mines included in this segment, leaving more tons sold from lower sales price mines. This has negatively impacted the average sales price in the steam coal segment, but has positively contributed to total company revenue.

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 $502 million in the three months ended September 30, 2010 compared to $453 million in the three months ended September 30, 2009. Operating costs related to the steam coal segment have increased primarily due to higher average costs per ton sold and higher volumes sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent   Change
Produced Steam Tons Sold (in millions)		13.7		12.9		0.8		6.2	%
Average Operating Costs Per Steam Ton Sold	$	36.58	$	34.99	$	1.59		4.5	%

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

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

• Power charges have increased due to higher rates charged by electric power companies in the period-to-period comparison.

• Health and retirement costs related to the active hourly work force have increased due to higher contributions 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 three months ended September 30, 2009 to $5.00 per hour in the three months ended September 30, 2010. Contributions to the 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.

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

• Average operating costs per steam ton sold decreased due to higher tons sold. Fixed costs are then allocated over higher tons therefore decreasing unit costs.

• Contract mining fees have been reduced due to fewer contractors being retained to mine our reserves in the period-to-period comparison.

Total CONSOL Energy expenses related to our actuarial liabilities were $71 million in the three months ended September 30, 2010 compared to $61 million for the three months ended September 30, 2009. The increase of $10 million is due primarily to changes in the discount rates used at the measurement dates and changes in assumptions which affect the amount amortized into earnings. See Note 3—“Components of Pension

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and Other Postretirement Benefit Plans Net Periodic Benefit Costs” and Note 4—“Components of Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation Net Periodic Benefit Costs” in the Condensed Consolidated Financial Statements for additional detail of total company expense increases.

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 accretion on the mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these liabilities are actuarially calculated for the company as a whole. The expenses associated with costs are allocated to operational units based on active employee counts or active salary dollars. Accretion 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 September 30, 2010 compared to $46 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Steam Tons Sold (in millions)		13.7		12.9		0.8		6.2	%
Average Provision Costs Per Steam Ton Sold	$	3.74	$	3.60	$	0.14		3.9	%

Provision cost per steam ton sold has increased in the period-to-period comparison due primarily to the higher actuarial liability expenses for the total company explained above.

Total company selling, general and administrative costs were $39 million in the three months ended September 30, 2010 compared to $32 million in the three months ended September 30, 2009. The $7 million increase in total company selling, general and administrative costs were primarily due to the following items.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Employee wages and related expenses	$	19	$	16	$	3		18.8	%
Commissions		3		2		1		50.0	%
Consulting and professional services		6		5		1		20.0	%
Other		11		9		2		22.2	%
Total Company Selling, General and Administrative Expenses	$	39	$	32	$	7		21.9	%

Total Company Selling, General and Administrative Expenses increased due to the following:

• Employee wages and related expenses increased $3 million which was primarily attributable to additional employees in the period-to-period comparison.

• Commission expense increased $1 million due to additional tons sold for which a third party was owed a commission in the period-to-period comparison.

• Consulting and professional services increased $1 million due to various corporate projects that have occurred throughout both periods, none of which were individually material.

• Other selling, general and administrative expenses have increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

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 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

49

related to the steam coal segment were $34 million in the three months ended September 30, 2010 compared to $36 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		13.7		12.9		0.8			6.2	%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.51	$	2.77	$	(0.26	)		(9.4	)%

Selling, general and administrative costs allocated to the steam coal segment have decreased as a result of the lower allocation of total costs as a percent of the total coal segment. These costs per unit sold also decreased due to higher volume of coal sold in the period-to-period comparison.

Depreciation, depletion and amortization for the steam coal segment was $70 million in the three months ended September 30, 2010 compared to $63 million in the three months ended September 30, 2009. The increase was due to additional equipment and infrastructure placed into service after the 2009 period. This increase was offset, in part, by higher tons sold which lowered the unit cost per ton sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Steam Tons Sold (in millions)		13.7		12.9		0.8		6.2	%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	5.07	$	4.88	$	0.19		3.9	%

HIGH VOL METALLURGICAL COAL SEGMENT

The high vol metallurgical coal segment contributed $12 million to total company earnings before income tax in the three months ended September 30, 2010. There was no activity in this segment in the prior period. This is a new market that has developed in 2010 and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical coal markets.

The high vol metallurgical coal segment revenue was $22 million in the three months ended September 30, 2010. Strength in the metallurgical 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.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		0.3		—		0.3		100.0	%
Average Sales Price Per High Vol Met Ton Sold	$	65.38	$	—	$	65.38		100.0	%

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

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Total high vol metallurgical coal segment costs were $13 million in the three months ended September 30, 2010. The cost components on a per unit basis are as follows:

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		0.3		—		0.3		100.0	%
Average Operating Costs Per High Vol Met Ton Sold	$	30.04	$	—	$	30.04		100.0	%
Average Provision Costs Per High Vol Met Ton Sold	$	2.76	$	—	$	2.76		100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	1.95	$	—	$	1.95		100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	4.73	$	—	$	4.73		100.0	%

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

LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical coal segment contributed $135 million to total company earnings before income tax in the three months ended September 30, 2010 compared to $28 million in the three months ended September 30, 2009. The increase is due primarily to the Buchanan mine operating for the entire 2010 period. The Buchanan mine was idled for most of July 2009 in response to the economic crisis in 2009 that significantly lowered the demand for low volatile metallurgical coal. The lower demand for this coal in the 2009 period was due to a drop in steel demand.

The low vol metallurgical coal segment sales revenue was $215 million in the three months ended September 30, 2010 compared to $63 million in the three months ended September 30, 2009. Higher sales revenues were due to higher average sales prices and higher tons sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.3		0.7		0.6		85.7	%
Average Sales Price Per Low Vol Met Ton Sold	$	165.22	$	93.02	$	72.20		77.6	%

Average sales prices for low vol metallurgical coal tons have increased 77.6% mainly due to the improvement in global economic conditions. The period-to-period comparison reflects higher demand for steel and steel related products.

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 low vol metallurgical coal segment were $62 million in the three months ended September 30, 2010 compared to $27 million in the three months ended September 30, 2009. Operating costs related to the low vol metallurgical coal segment have increased primarily due to higher average costs per ton sold and higher volumes sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.3		0.7		0.6		85.7	%
Average Operating Costs Per Low Vol Met Ton Sold	$	47.98	$	39.59	$	8.39		21.2	%

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Higher average operating costs for low vol metallurgical coal tons sold is primarily related to the following items:

• Higher operating and supply costs per unit have been incurred primarily due to additional repairs and maintenance, additional contractor services and additional roof support. These additional costs were due, in part, to longwall overhauls completed, roof support plan changes and various other projects completed at the Buchanan mine.

• Higher production taxes per unit sold have been incurred primarily attributable to the higher average sales price received in the period-to-period comparison.

• Higher royalty expense per unit sold was attributable to the higher average sales price received in the period-to-period comparison.

• Higher labor costs per unit sold have been incurred due to higher hourly wage rates, higher employee counts and additional overtime in the period-to-period comparison.

• These increases in unit costs were offset, in part, by additional sales tons. Fixed costs are then allocated over higher tons therefore decreasing unit costs.

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 accretion on the mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these liabilities are actuarially calculated for the company as a whole. The expenses associated with costs are allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. The provision expense attributable to the low vol metallurgical coal segment was $7 million in the three months ended September 30, 2010 compared to $3 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.3		0.7		0.6		85.7	%
Average Provision Costs Per Low Vol Met Ton Sold	$	5.29	$	4.74	$	0.55		11.6	%

Provision cost per low vol metallurgical ton sold has increased in the period-to-period comparison due primarily to the higher actuarial liability expenses for the total company explained in the steam coal segment. The overall increase in company costs has increased the total dollars allocated to the low vol metallurgical coal segment proportionately more than the increase in the tons sold.

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 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 low vol metallurgical coal segment were $5 million in the three months ended September 30, 2010 compared to $2 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.3		0.7		0.6		85.7	%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	3.60	$	3.27	$	0.33		10.1	%

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Selling, administrative and other costs allocated to the low vol metallurgical coal segment have increased due to the total company increase in these costs explained in the steam coal segment. The increase in low vol metallurgical tons sold offset, in part, the increase in dollars allocated to this segment.

Depreciation, depletion and amortization was $6 million in the three months ended September 30, 2010 compared to $3 million in the three months ended September 30, 2009. The increase in depreciation, depletion and amortization was due to additional equipment and infrastructure placed into service after the 2009 period. This increase was offset, in part, by higher tons sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.3		0.7		0.6		85.7	%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	4.65	$	3.52	$	1.13		32.1	%

OTHER COAL SEGMENT

The Other Coal segment had a loss before income tax of $114 million in the three months ended September 30, 2010 compared to a loss before income tax of $97 million in the three months ended September 30, 2009. The Other Coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Other coal segment produced coal sales include revenue from the sale of incidental tonnage recovered during the reclamation process at idled facilities. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold from these activities are incidental to total company production or sales.

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 $1 million in the three months ended September 30, 2010. Revenues from purchased coal sales were insignificant in the three months ended September 30, 2009.

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 $37 million in the three months ended September 30, 2010 compared to $36 million in the three months ended September 30, 2009.

Miscellaneous other income was $18 million in the three months ended September 30, 2010 compared to $10 million in the three months ended September 30, 2009. Gains on sales of assets, included in miscellaneous other income, were $8 million in the three months ended September 30, 2010. Gains on sales of assets were insignificant in the three months ended September 30, 2009.

Other coal segment total cost was $173 million in the three months ended September 30, 2010 compared to $143 million in the three months ended September 30, 2009. The increase of $30 million was due to the following items:

• Closed and idle mine costs increased approximately $26 million in the three months ended September 30, 2010 compared to the three months ended September 30, 2009. 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 has increased. Also,

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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. A specific detailed reclamation plan has been developed and the costs associated with the increased reclamation have been estimated. The present value of the reclamation liability has been estimated to equal $76 million at September 30, 2010. As a result, $28 million of expense was recognized in the three months ended September 30, 2010. Also, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. Due to the mine plan change, a portion of the previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $16 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.

• Other expenses related to the coal segment were $4 million higher in the three months ended September 30, 2010 compared to the three months ended September 30, 2009. These increases 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 September 30, 2010 compared to the three months ended September 30, 2009:

The gas segment contributed $36 million to earnings before income tax in the three months ended September 30, 2010 compared to $58 in the three months ended September 30, 2009. A detailed variance explanation is described below.

	For the Three Months Ended September 30, 2010												Difference to Three Months Ended September 30, 2009
	CBM		Conven- tional			Marcellus		Other Gas			Total Gas		CBM			Conven- tional			Marcellus			Other Gas			Total Gas
Sales:
Produced	$	139	$	45		$	15	$	3		$	202	$	(3	)	$	44		$	6		$	1		$	48
Related Party		2		—			—		—			2		1			—			—			—			1
Total Outside Sales		141		45			15		3			204		(2	)		44			6			1			49
Gas Royalty Interest		—		—			—		18			18		—			—			—			10			10
Purchased Gas		—		—			—		4			4		—			—			—			3			3
Other Income		—		—			—		2			2		—			—			—			1			1
Total Revenue and Other Income		141		45			15		27			228		(2	)		44			6			15			63
Lifting		13		12			1		2			28		1			11			1			1			14
Gathering		24		5			4		1			34		3			5			2			—			10
General & Administration		16		7			2		—			25		1			7			1			—			9
Depreciation, Depletion and Amortization		29		23			6		1			59		2			22			3			1			28
Gas Royalty Interest		—		—			—		16			16		—			—			—			10			10
Purchased Gas		—		—			—		3			3		—			—			—			2			2
Exploration and Other Costs		—		—			—		13			13		—			—			—			7			7
Other Corporate Expenses		—		—			—		12			12		—			—			—			5			5
Interest Expense		—		—			—		2			2		—			—			—			—			—
Total Cost		82		47			13		50			192		7			45			7			26			85
Earnings Before Noncontrolling Interest and Income Tax		59		(2	)		2		(23	)		36		(9	)		(1	)		(1	)		(11	)		(22	)
Noncontrolling Interest		—		—			—		—			—		—			—			—			—			—
Earnings Before Income Tax	$	59	$	(2	)	$	2	$	(23	)	$	36	$	(9	)	$	(1	)	$	(1	)	$	(11	)	$	(22	)

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COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $59 million to the total company earnings before income tax in the three months ended September 30, 2010 compared to $68 million in the three months ended September 30, 2009.

CBM sales revenues were $141 million in the three months ended September 30, 2010 compared to $143 million in the three months ended September 30, 2009. The $2 million decrease was primarily due to a 6.0% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 5.5% increase in average volumes sold.

	For the Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		23.0		21.8		1.2			5.5	%
Average CBM Sales price per thousand cubic feet	$	6.16	$	6.55	$	(0.39	)		(6.0	)%

The decrease in CBM 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 13.1 billion cubic feet of our produced CBM gas sales volumes for the three months ended September 30, 2010 at an average price of $7.47 per thousand cubic feet. In the three months ended September 30, 2009, these financial hedges represented 13.2 billion cubic feet at an average price of $8.69 per thousand cubic feet. Although average market prices have increased slightly in the period-to-period comparison, we have sold hedged volumes under lower average prices in the 2010 period compared to the 2009 period. CBM sales volumes increased 1.2 billion cubic feet primarily due to additional wells coming on line from our on-going drilling program.

Total costs for the CBM segment were $82 million for the three months ended September 30, 2010 compared to $75 million for the three months ended September 30, 2009. Higher costs in the period-to-period comparison are primarily related to increased volumes sold in addition to slightly higher unit costs. Unit cost variances are explained below.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		23.0		21.8		1.2		5.5	%
Average CBM lifting costs per thousand cubic feet sold	$	0.59	$	0.57	$	0.02		3.5	%
Average CBM gathering costs per thousand cubic feet sold	$	1.06	$	0.98	$	0.08		8.2	%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.69	$	0.66	$	0.03		4.5	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.24	$	1.22	$	0.02		1.6	%

CBM lifting costs were $13 million in the three months ended September 30, 2010 compared to $12 million in the three months ended September 30, 2009. The $1 million increase was primarily due to the increase in sales volumes and a 3.5% increase in average CBM unit costs. Average CBM lifting costs were higher in the period-to-period comparison primarily due to higher severance taxes. Severance taxes are calculated as a percentage of sales before the impact of hedging. Market prices, before impacts of hedging, for gas have increased in the period-to-period comparison. The increase in severance taxes is related to Buchanan County, Virginia tax settlement that was finalized earlier this year which changed deductions allowed in the calculation of severance tax due when the price of gas falls between certain ranges. This increase was offset, in part, by lower salt water disposal costs related to recycling water produced from our wells to be used in hydraulic fracturing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Increases in costs were also offset, in part, by the impact of higher volumes on fixed costs lowering costs per unit.

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CBM gathering costs were $24 million in the three months ended September 30, 2010 compared to $21 million in the three months ended September 30, 2009. The $3 million increase reflects 5.5% of additional volumes and an 8.2% increase in average CBM gathering costs. Higher average CBM gathering unit costs are related to higher power charges and additional in-transit charges, offset, in part, by the impact of higher volumes on fixed charges. Power charges have increased in the period-to-period comparison due to higher utility rates being charged in the current year. In-transit charges have increased due to additional firm transportation capacity being purchased after the 2009 period to assure delivery of additional volumes being produced.

General and administrative costs attributable to the Total Gas segment were $25 million in the three months ended September 30, 2010 compared to $16 million in the three months ended September 30, 2009. The $9 million increase was attributable to additional staffing and additional corporate service charges from CONSOL Energy. With the Dominion Acquisition, which closed on April 30, 2010, the majority of the operational support personnel were retained. The additional employees are supporting the ramp up in the gas drilling program by providing various services. The Dominion Acquisition also resulted in additional support charges from CONSOL Energy. These charges are primarily based on revenue and capital expenditure projections between coal and gas.

General and administrative costs for the CBM segment were $16 million in the three months ended September 30, 2010 compared to $15 million in the three months ended September 30, 2009. General and administrative costs attributable to the Total Gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The total general and administrative costs increased in the period-to-period comparison offset, in part, by higher volumes of CBM gas sold, resulted in a slight unit cost increase in the period-to-period comparison.

Depreciation, depletion and amortization attributable to the CBM segment was $29 million in the three months ended September 30, 2010 compared to $27 million in the three months ended September 30, 2009. There was approximately $22 million, or $0.96 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2010. The production portion of depreciation, depletion and amortization was $21 million, or $0.95 per unit-of-production in the three months ended September 30, 2009. The CBM unit-of-production rate increased due to revised rates which are generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. The addition of the assets and related reserves acquired in the Dominion Acquisition caused the rate to increase slightly due to the proportion of asset value, which is the purchase price fair value assigned to these assets, to the proved or proved developed reserves acquired. There was approximately $7 million, or $0.28 average per unit cost of depreciation, depletion and amortization relating to gathering and other equipment that is reflected on a straight line basis in the three months ended September 30, 2010. The non-production related depreciation, depletion and amortization was $6 million, or $0.27 per thousand cubic feet in the three months ended September 30, 2009. The increase was related to additional gathering assets placed in service after the 2009 period.

CONVENTIONAL GAS SEGMENT

The conventional segment had a loss before income tax of $2 million in the three months ended September 30, 2010 compared to a loss before income tax of $1 million in the three months ended September 30, 2009.

Conventional segment sales revenues were $45 million in the three months ended September 30, 2010 compared to $1 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		9.0		0.4		8.6		2,150.0	%
Average Conventional Sales price per thousand cubic feet	$	5.00	$	3.96	$	1.04		26.3	%

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Conventional sales volumes increased 8.6 billion cubic feet in the three months ended September 30, 2010 compared to the 2009 period primarily due to the Dominion Acquisition which closed on April 30, 2010. Approximately 95% of the acquired producing wells are conventional type wells. Average sales price increased due to the improvement in general market prices in the period-to-period comparison.

Total costs for the conventional segment were $47 million in the three months ended September 30, 2010 compared to $2 million in the three months ended September 30, 2009. The increase is attributable to increased variable costs associated with the additional volumes produced offset, in part, by lower average unit costs. A detailed analysis of cost categories is not meaningful due to the significant change in this segment related to the Dominion Acquisition and therefore will not be presented.

	For the Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		9.0		0.4		8.6			2,150.0	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.37	$	3.53	$	(2.16	)		(61.2	)%
Average Conventional gathering costs per thousand cubic feet sold	$	0.60	$	0.47	$	0.13			27.7	%
Average Conventional general & administrative costs per thousand cubic feet sold	$	0.80	$	0.32	$	0.48			150.0	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.50	$	2.05	$	0.45			22.0	%

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $2 million to the total company earnings before income tax in the three months ended September 30, 2010 compared to $3 million in the three months ended September 30, 2009.

The Marcellus segment sales revenues were $15 million in the three months ended September 30, 2010 compared to $9 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.3		2.3		1.0		43.5	%
Average Marcellus Sales price per thousand cubic feet	$	4.65	$	3.99	$	0.66		16.5	%

The increase in Marcellus average sales price is the result of an improvement in general market prices and various gas swap transactions that occurred in the three months ended September 30, 2010. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 0.4 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended September 30, 2010 at an average price of $5.05 per thousand cubic feet. There were no gas swap transactions that occurred in the three months ended September 30, 2009. The increase in sales volumes is primarily due to additional wells coming online from our on-going drilling program. At September 30, 2010, there were 45 Marcellus Shale wells in production including 17 wells acquired in the Dominion Acquisition. At September 30, 2009, there were 19 Marcellus Shale wells in production.

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Total costs for the Marcellus segment were $13 million in the three months ended September 30, 2010 compared to $6 million in the three months ended September 30, 2009. The increase was primarily due to the additional volumes sold.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.3		2.3		1.0		43.5	%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.40	$	0.08	$	0.32		400.0	%
Average Marcellus gathering costs per thousand cubic feet sold	$	1.05	$	0.92	$	0.13		14.1	%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.74	$	0.50	$	0.24		48.0	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.74	$	1.28	$	0.46		35.9	%

Marcellus lifting costs were $1 million in the three months ended September 30, 2010. These costs were insignificant in the three months ended September 30, 2009. The increase in unit costs is primarily attributable to additional repairs and maintenance expense, additional contractual services and additional property taxes.

Marcellus gathering costs were $4 million in the three months ended September 30, 2010 compared to $2 million in the three months ended September 30, 2009. Average gathering costs increased $0.13 per unit primarily due to additional power charges, additional contractual service charges and additional compression charges. Power charges have increased per unit due to higher rates being charged by the utilities. Additional contract service charges have been incurred in the period-to-period comparison primarily due to additional gathering lines in service that need maintained. Additional compression charges have been incurred primarily due to growing the Marcellus field in the period-to-period comparison requiring additional compression. Unused capacity charges for firm transportation are reflected in Other Corporate Charges.

General and administrative costs on the Marcellus gas segment were $2 million in the three months ended September 30, 2010, which reflects an increase of $1 million 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 a combination of production and employee counts. The total general and administrative costs increased in the period-to-period comparison offset, in part, by higher volumes of Marcellus gas sold resulting in a unit cost increase in the period-to-period comparison. General and administrative costs were $0.74 per thousand cubic feet sold in the three months ended September 30, 2010 compared to $0.50 per thousand cubic feet sold in the three months ended September 30, 2009. The Total Gas segment general and administrative cost increase was explained in the CBM segment.

Depreciation, depletion and amortization costs were $6 million in the three months ended September 30, 2010 compared to $3 million in the three months ended September 30, 2009. There was approximately $5 million, or $1.55 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 September 30, 2010. There was approximately $2 million, or $1.05 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 September 30, 2009. 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. There was approximately $1 million, or $0.19 per thousand cubic feet per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the three months ended September 30, 2010. There was approximately $1 million, or $0.23 per thousand cubic feet per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the three months ended September 30, 2009.

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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 production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $3 million in the three months ended September 30, 2010 and $2 million in the three months ended September 30, 2009. Total costs related to these other sales were $4 million in the 2010 period compared to $2 million in the 2009 period. The increase in costs in the period-to-period comparison was primarily attributable to depreciation, depletion and amortization. Higher depreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. The higher rate was due to an increase in the unit-of-production rates in 2010. The increase was related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. Increased costs were also attributable to higher severance taxes. Higher severance taxes were attributable to higher average sales prices in the period-to-period comparison. A per unit analysis of the other operating costs in Chattanooga is not meaningful due to the low volumes produced in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy 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 revenue were $18 million in the three months ended September 30, 2010 compared to $8 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		4.1		2.4		1.7		70.8	%
Average Sales Price Per thousand cubic feet	$	4.43	$	3.46	$	0.97		28.0	%

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 $4 million in the three months ended September 30, 2010 compared to $1 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)		0.6		0.4		0.2		50.0	%
Average Sales Price Per thousand cubic feet	$	5.54	$	3.53	$	2.01		56.9	%

Other income increased $1 million in the three months ended September 30, 2010 compared to the 2009 period due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

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Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy 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 $16 million in the three months ended September 30, 2010 compared to $6 million in the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		4.1		2.4		1.7		70.8	%
Average Cost Per thousand cubic feet sold	$	4.01	$	2.57	$	1.44		56.0	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas 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 $3 million in the three months ended September 30, 2010 compared to $1 million for the three months ended September 30, 2009.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)		0.6		0.5		0.1		20.0	%
Average Cost Price Per thousand cubic feet sold	$	5.49	$	2.45	$	3.04		124.1	%

Exploration and other costs have increased $7 million in the period-to-period comparison. The increase in these costs was due to the following items.

	For the Three Months Ended September 30,
	2010		2009		Variance		Percent Change
Dry hole and lease expiration costs	$	11	$	5	$	6		120.0	%
Exploration		2		1		1		100.0	%
Total Exploration and Other Costs	$	13	$	6	$	7		116.7	%

Dry hole and lease expiration costs were $6 million higher due to lease surrenders in the current period and additional dry wells in the period-to-period comparison.

Exploration costs have increased $1 million due to various transactions that have occurred throughout both periods, none of which were individually material.

Other corporate expenses increased $5 million in the period-to-period comparison.

	For the Three Months Ended September 30,
	2010		2009		Variance			Percent Change
Bank fees	$	2	$	—	$	2			100.0	%
Stock-based compensation		4		3		1			33.3	%
Short-term incentive compensation		2		3		(1	)		(33.3	)%
Other		4		1		3			300.0	%
Total Other Corporate Expenses	$	12	$	7	$	5			71.4	%

Bank fees are higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. In May 2010, the facility was amended to allow $700 million of borrowings and was extended through 2014.

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Stock-based compensation is higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of the Dominion Acquisition. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.

The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit cost goals. Short-term incentive compensation expense is lower in the 2010 period compared to the 2009 period due to adjustments to the payment projections.

Other corporate related expense increased $3 million in the period-to-period comparison due to various transactions throughout both periods, none of which were individually material.

Interest expense related to the gas segment was $2 million in the three months ended September 30, 2010 and the three months ended September 30, 2009. Interest is incurred by the gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interest entity. No significant changes in these components occurred 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 CONSOL Energy gas segment holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas segment has been determined to be the primary beneficiary due to guarantees of the third party’s bank debt related to their purchase of drilling rigs. The third party entity provides drilling services primarily to the CONSOL Energy gas segment. CONSOL Energy 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 amounts reflects the third party’s variance in earnings in the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the three months ended September 30, 2010 compared to the three months ended September 30, 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 had a loss before income tax of $63 million in the three months ended September 30, 2010 compared to income before tax of $2 million in the three months ended September 30, 2009. The other segment also includes total company income tax expense of $16 million in the three months ended September 30, 2010 compared to $35 million in the three months ended September 30, 2009.

	Three Months Ended September 30,
	2010			2009			Variance			Percentage Change
Sales—Outside	$	75		$	68		$	7			10.3	%
Other Income		5			9			(4	)		(44.4	)%
Total Revenue		80			77			3			3.9	%
Cost of Goods Sold and Other Charges		72			62			10			16.1	%
Depreciation, Depletion & Amortization		4			5			(1	)		(20.0	)%
Interest Expense		64			6			58			966.7	%
Taxes Other Than Income Tax		3			2			1			50.0	%
Total Costs		143			75			68			90.7	%
Earnings Before Income Tax		(63	)		2			(65	)		(3,250.0	)%
Income Tax		16			35			(19	)		(54.3	)%
Net Income	$	(79	)	$	(33	)	$	(46	)		139.4	%

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Industrial supplies:

Total revenue from industrial supplies was $48 million in the three months ended September 30, 2010 compared to $50 million in the three months ended September 30, 2009. The reduction was related to slightly lower sales volumes.

Total costs related to industrial supply sales were $46 million in the three months ended September 30, 2010 compared to $51 million in the three months ended September 30, 2009. The decrease of $5 million was primarily due to changes in last-in-first-out valuations.

Transportation operation:

Total revenue from transportation operations was $30 million in the three months ended September 30, 2010 compared to $20 million in the three months ended September 30, 2009. The increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Total costs related to the transportation operations were $19 million in the three months ended September 30, 2010 compared to $14 million in the three months ended September 30, 2009. The increase of $5 million was related to the additional through-put handled by the operation.

Miscellaneous other:

Additional other income of $2 million was recognized in the three months ended September 30, 2010 compared to $7 million in the three months ended September 30, 2009. The $5 million decrease was primarily due to lower equity in earnings of affiliates in the current period compared to the prior year period. The change was also due to various transactions that have occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $78 million in the three months ended September 30, 2010 compared to $10 million in the three months ended September 30, 2009. Other corporate costs increased due to the following.

• Interest expense was $64 million in the three months ended September 30, 2010 compared to $6 million in the three months ended September 30, 2009. The increase of $58 million was primarily related to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition.

• Bank fees of $5 million were incurred in the three months ended September 30, 2010 compared to $1 million in the three months ended September 30, 2009. The increase of $4 million was primarily related to the fees associated with the increase in capacity of the revolving credit facility.

• Fees related to disposing non-core assets of $2 million were incurred in the three months ended September 30, 2010.

• Various other corporate items increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 17.3% in the three months ended September 30, 2010 compared to 27.4% in the three months ended September 30, 2009. The decrease in the effective tax rate for the three month period ending September 30, 2010 as compared to the three month period ending September 30, 2009 is attributable the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas

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pre-tax earnings also impact the benefit of percentage depletion on the effective tax rate. See “Note 5-Income Taxes” of the Condensed Consolidated Financial Statements of this Form 10-Q.

	For the Three Months Ended September 30,
	2010			2009			Variance			Percentage Change
Total Company Earnings Before Income Tax	$	91		$	129		$	(38	)		(29.5	)%
Income Tax Expense	$	16		$	35		$	(19	)		(54.3	)%
Effective Income Tax Rate		17.3	%		27.4	%		(10.1	)%

Results of Operations

Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009

Net Income Attributable to CONSOL Energy

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $242.3 million, or $1.13 per diluted share for the nine months ended September 30, 2010. Net income attributable to CONSOL Energy shareholders was $396.5 million, or $2.17 per diluted share, for the nine months ended September 30, 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 Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. The aggregate high volatile coal segment includes Bailey, Enlow Fork, Fola Complex and Emery coal sales. The aggregate low volatile segment includes the Buchanan mine. The other coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal segment but not allocated to each individual mine.

The average sales price and total costs for all active coal operations was as follows:

	Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Average Sales Price per ton sold	$	61.42	$	58.95	$	2.47			4.2	%
Average Costs per ton sold		46.05		43.23		2.82			6.5	%
Margin	$	15.37	$	15.72	$	(0.35	)		(2.2	)%

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 average sales price and total costs for all active gas operations was as follows:

	Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	6.22	$	6.75	$	(0.53	)		(7.9	)%
Average Costs per thousand cubic feet sold		3.88		3.43		0.45			13.1	%
Margin	$	2.34	$	3.32	$	(0.98	)		(29.5	)%

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

Year-to-Date TOTAL COAL SEGMENT ANALYSIS for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009:

The coal segment contributed $349 million of earnings before income tax in the nine months ended September 30, 2010 compared to $405 million in the 2009 period. Variances by the individual coal segments are discussed below.

	Nine Months Ended September 30, 2010											Difference to Nine Months Ended September 30, 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	$	2,203	$	135	$	491	$	7		$	2,836	$	(129	)	$	135	$	343	$	7		$	356
Purchased Coal		—		—		—		26			26		—			—		—		4			4
Total Outside Sales		2,203		135		491		33			2,862		(129	)		135		343		11			360
Freight Revenue		—		—		—		97			97		—			—		—		3			3
Other Income		5		6		—		41			52		1			6		—		(15	)		(8	)
Total Revenue and Other Income		2,208		141		491		171			3,011		(128	)		141		343		(1	)		355
Costs and Expenses:
Total operating costs		1,373		53		173		224			1,823		98			53		91		(6	)		236
Total provisions		149		6		20		113			288		15			6		8		99			128
Total administrative & other costs		108		4		14		69			195		1			4		6		3			14
Depreciation, depletion and amortization		198		8		15		38			259		7			8		5		10			30
Total Costs and Expenses		1,828		71		222		444			2,565		121			71		110		106			408
Freight Expense		—		—		—		97			97		—			—		—		3			3
Total Cost		1,828		71		222		541			2,662		121			71		110		109			411
Earnings Before Income Taxes	$	380	$	70	$	269	$	(370	)	$	349	$	(249	)	$	70	$	233	$	(110	)	$	(56	)

STEAM COAL SEGMENT

The steam coal segment contributed $380 million to total company earnings before income tax in the nine months ended September 30, 2010 compared to $629 million in the nine months ended September 30, 2009.

Steam coal revenue was $2,203 million in the nine months ended September 30, 2010 compared to $2,332 million in the nine months ended September 30, 2009. The $129 million decrease was attributable to a decrease in tons sold and lower sales prices received in the period-to-period comparison.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		40.7		40.8		(0.1	)		(0.2	)%
Average Sales Price Per Steam Ton Sold	$	54.09	$	57.17	$	(3.08	)		(5.4	)%

Steam coal average sales price is lower in the 2010 period as a result of higher average sales price mines, such as Bailey and Enlow Fork, selling coal in the high vol met market. This impacted the steam segment due to

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the proportionate lower tons sold from the higher sales price mines included in this segment, leaving more tons sold from lower sales price mines. This has negatively impacted the average sales price on the steam coal segment, although total company revenue has been improved. Produced steam coal inventory was 2.1 million tons at September 30, 2010. Steam coal sales tons are lower in the period-to-period comparison primarily due to selling approximately 1.8 million tons of this coal on the high vol met market at approximately $19.56 per ton higher sales price. This decrease in Steam tons sold was offset, in part, by the Shoemaker mine restarting production early in 2010 after being idled throughout the nine months ended 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Also, Blacksville #2 Mine production increased due to the mine being idled for most of September 2009 in order to manage inventory levels during the economic crisis experience in 2009. The mine has operated throughout the nine months ended September 30, 2010.

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 $1,373 million in the nine months ended September 30, 2010 compared to $1,275 million in the nine months ended September 30, 2009. Operating costs related to the steam coal segment have increased primarily due to higher average costs per ton sold.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		40.7		40.8		(0.1	)		(0.2	)%
Average Operating Costs Per Steam Ton Sold	$	33.72	$	31.28	$	2.44			7.8	%

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

• Steam coal unit costs are higher in the 2010 period as a result of lower cost mines, such as Bailey and Enlow, selling coal in the high vol met market. This impacted the steam segment due to the proportionate lower tons sold from the lower cost mines included in this segment, leaving more tons sold from higher cost mines. 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. The 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. Average employee counts increased approximately 18% at our active mining operations in order to meet our staffing needs.

• Health and retirement costs related to the active hourly work force have increased due to higher contributions 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 nine months ended September 30, 2009 to $5.00 per hour in the nine months ended September 30, 2010. Contributions to the 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 charges have increased due to higher rates charges by electric power companies in the period-to-period comparison.

These increases in costs per unit of steam coal sold were offset, in part, by reduced contract mining fees due to fewer contractors being retained to mine our reserves in the period-to-period comparison.

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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 accretion on the mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these liabilities are actuarially calculated for the company as a whole. The expenses associated with costs are allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. The provision expense attributable to the steam coal segment was $149 million in the nine months ended September 30, 2010 compared to $134 million in the nine months ended September 30, 2009.

Total CONSOL Energy expenses related to our actuarial liabilities were $216 million in the nine months ended September 30, 2010 compared to $182 million for the nine months ended September 30, 2009. The increase of $34 million is due primarily to changes in the discount rates used at the measurement date, which is December 31, and changes in assumptions which affect the amount amortized into earnings. See Note 3—“Components of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs” and Note 4—“Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation Net Periodic Benefit Costs” in the Consolidated Financial Statements for additional detail of total company expense increases.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		40.7		40.8		(0.1	)		(0.2	)%
Average Provision Costs Per Steam Ton Sold	$	3.67	$	3.30	$	0.37			11.2	%

Provision cost per steam ton sold have increased in the period-to-period comparison due primarily to the higher actuarial liability expenses for the total company explained above. The overall increase in company costs has increased the total dollars allocated to the steam coal segment. Higher dollars allocated and lower sales volumes negatively impacted unit cost per steam ton sold.

Total company selling, general and administrative costs were $108 million in the nine months ended September 30, 2010 compared to $98 million in the nine months ended September 30, 2009. The $10 million increase in total company selling, general and administrative costs were primarily due the following items.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Employee wages and related expenses	$	52	$	47	$	5		10.6	%
Commissions		10		5		5		100.0	%
Miscellaneous		46		46		—		—
Total Selling, General and Administrative Costs	$	108	$	98	$	10		10.2	%

Employee wages and related expenses increased $5 million primarily attributable to additional employees in the period-to-period comparison. Additional employees are related to the personnel that were retained with the Dominion Acquisition.

Commission expenses increased $5 million due to additional tons sold for which a third party was owed a commission compared to the prior year period.

Miscellaneous selling, general and administrative expenses have remained consistent at $46 million in the period-to-period comparison.

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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 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 $108 million in the nine months ended September 30, 2010 compared to $107 million in the nine months ended September 30, 2009. Selling, general and administrative costs allocated to the steam coal segment have increased due to the total company increase in these costs explained above. Commissions related to the steam segment have increased in the period-to-period comparison, causing the average unit cost to increase. The increase is primarily due to additional tons sold which are subject to a third party commission.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		40.7		40.8		(0.1	)		(0.2	)%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.65	$	2.63	$	0.02			0.8	%

Depreciation, depletion and amortization for the steam coal segment was $198 million in the nine months ended September 30, 2010 compared to $191 million in the nine months ended September 30, 2009. The increase in depreciation, depletion and amortization was due to additional equipment and infrastructure placed into service after the 2009 period.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		40.7		40.8		(0.1	)		(0.2	)%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.86	$	4.67	$	0.19			4.1	%

HIGH VOL METALLURGICAL COAL SEGMENT

The high vol metallurgical coal segment contributed $70 million to total company earnings before income tax in the nine months ended September 30, 2010. There was no activity in this segment in the prior year period. This is a new market that has developed in 2010 and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical coal markets.

The high vol metallurgical coal segment revenue was $135 million in the nine months ended September 30, 2010. Strength in the metallurgical 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.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		1.8		—		1.8		100.0	%
Average Sales Price Per High Vol Met Ton Sold	$	73.65	$	—	$	73.65		100.0	%

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

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Total high vol metallurgical coal segment costs were $71 million in the nine months ended September 30, 2010. The cost components on a per unit basis are as follows:

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		1.8		—		1.8		100.0	%
Average Operating Costs Per High Vol Met Ton Sold	$	28.90	$	—	$	28.90		100.0	%
Average Provision Costs Per High Vol Met Ton Sold	$	3.08	$	—	$	3.08		100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	2.26	$	—	$	2.26		100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	4.24	$	—	$	4.24		100.0	%

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

LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical coal segment contributed $269 million to total company earnings before income tax in the nine months ended September 30, 2010 compared to $36 million in the nine months ended September 30, 2009. The increase is due primarily to the Buchanan mine being idled for approximately five of the nine months ended September 30, 2009. The mine was idled in response to the economic crisis in 2009 that significantly lowered the demand for low volatile metallurgical coal, primarily due to the drop in steel demand.

The low vol metallurgical coal segment sales revenue was $491 million in the nine months ended September 30, 2010 compared to $148 million in the nine months ended September 30, 2009. Higher sales revenues were due to higher average sales prices and higher tons sold.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		3.5		1.3		2.2		169.2	%
Average Sales Price Per Low Vol Met Ton Sold	$	140.27	$	115.50	$	24.77		21.4	%

Average sales prices for low vol met tons have increased 21.4% mainly due to the strengthening of the global market for steel and steel related products compared to the prior year. Sales volumes have improved due to operating the Buchanan mine for the entire nine months of 2010 compared to four of the nine months of 2009 as discussed above.

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Total costs for the low vol coal segment were $222 million in the nine months ended September 30, 2010 compared to $112 million for the nine months ended September 30, 2009. A comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low vol coal segment in 2009 as discussed above. The improvements in unit costs are related to operating the mine throughout the nine months ended September 30, 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 cost for this segment.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		3.5		1.3		2.2			169.2	%
Average Operating Costs Per Low Vol Met Ton Sold	$	49.41	$	63.90	$	(14.49	)		(22.7	)%
Average Provision Costs Per Low Vol Met Ton Sold	$	5.81	$	9.35	$	(3.54	)		(37.9	)%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	3.97	$	6.36	$	(2.39	)		(37.6	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	4.35	$	7.42	$	(3.07	)		(41.4	)%

OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before income taxes by $370 million in the nine months ended September 30, 2010 compared to $260 million in the nine months ended September 30, 2009. The Other Coal segment includes purchased coal activities, idled mine activities as well as various other activities assigned to the coal segment but not allocated to each individual mine.

Other coal segment produced coal sales include revenue from the sale of incidental tonnage recovered during the reclamation process at idled facilities. The primary focus of activity at these locations is reclaiming disturbed land in accordance with mining permit requirements after final mining has occurred. The tons sold from these activities are incidental to total company production or sales.

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 $26 million in the nine months ended September 30, 2010 compared to $22 million in the nine months ended September 30, 2009.

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 $97 million in the nine months ended September 30, 2010 compared to $94 million in the nine months ended September 30, 2009.

Miscellaneous other income was $41 million in the nine months ended September 30, 2010 compared to $56 million in the nine months ended September 30, 2009. The $15 million decrease is made up of the following items:

• In the nine months ended September 30, 2009, $12 million of income was recognized related to contracts with certain customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to release them from the requirement of taking delivery of previously committed tons. No such transactions were entered into in the nine months ended September 30, 2010.

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• Coal royalty income from third parties was $10 million in the nine months ended September 30, 2010 compared to $13 million in the nine months ended September 30, 2009. The decrease is related to lower tons mined by third parties from our coal reserves.

• In the nine months ended September 30, 2009, mark-to-market adjustments for free standing coal sales options resulted in approximately $2 million reversal of previously recognized unrealized losses. The reversal of losses was primarily due to the decrease in market price of coal at September 30, 2009 compared to December 31, 2008. No such transactions existed in the nine months ended September 30, 2010.

• Other miscellaneous income related to the coal segment decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

• Gain on sales of assets attributable to the other Coal segment was $8 million in the nine months ended September 30, 2010 compared to $4 million in the nine months ended September 30, 2009. The change is related to various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $541 million in the nine months ended September 30, 2010 compared to $432 million in the nine months ended September 30, 2009. The increase of $109 million is due to the following items:

• Closed and idle mine costs increased approximately $82 million in the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. 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 has increased approximately $81 million. Closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $13 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.

• Litigation expense of $25 million was recognized in the nine months ended September 30, 2010 related to a settlement that was reached in June 2010. The litigation was related to water discharge from our Buchanan mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. The settlement included $25 million of damages which were expensed in the 2010 year-to-date period.

• Other expenses related to the coal segment were $17 million higher in the 2010 period compared to the 2009 period primarily related to the legal settlement which included the sale of Jones Fork that resulted in a loss of approximately $11 million in the nine months ended September 30, 2010. The remaining $6 million increase was related to various transactions that were incurred throughout both periods, none of which were individually material.

• Purchased coal consists 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. These costs were $30 million in the nine months ended September 30, 2010 compared to $28 million in the nine months ended September 30, 2009. The increase of $2 million was primarily due to increased purchased coal volumes.

• Litigation expense of $17 million was recognized in the nine months ended September 30, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.

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Year-to-Date TOTAL GAS SEGMENT ANALYSIS for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009:

The gas segment contributed $163 million to earnings before income tax in the nine months ended September 30, 2010 compared to $200 in the nine months ended September 30, 2009. A detailed variance explanation is described below.

	For the Nine Months Ended September 30, 2010												Difference to Nine Months Ended September 30, 2009
	CBM		Conven- tional		Marcellus		Other Gas			Total Gas			CBM			Conven- tional		Marcellus		Other Gas			Total Gas
Sales:
Produced	$	449	$	78	$	34	$	5		$	566		$	7		$	72	$	19	$	2		$	100
Related Party		5		—		—		—			5			3			—		—		—			3
Total Outside Sales		454		78		34		5			571			10			72		19		2			103
Gas Royalty Interest		—		—		—		47			47			—			—		—		17			17
Purchased Gas		—		—		—		8			8			—			—		—		4			4
Other Income		—		—		—		3			3			—			—		—		(1	)		(1	)
Total Revenue and Other Income		454		78		34		63			629			10			72		19		22			123
Lifting		39		18		3		1			61			3			16		2		1			22
Gathering		74		8		8		2			92			10			7		4		2			23
General & Administration		47		12		5		(1	)		63			—			11		3		(2	)		12
Depreciation, Depletion and Amortization		83		39		13		5			140			14			36		8		3			61
Gas Royalty Interest		—		—		—		41			41			—			—		—		18			18
Purchased Gas		—		—		—		7			7			—			—		—		4			4
Exploration and Other Costs		—		—		—		21			21			—			—		—		6			6
Other Corporate Expenses		—		—		—		40			40			—			—		—		18			18
Interest Expense		—		—		—		6			6			—			—		—		—			—
Total Cost		243		77		29		122			471			27			70		17		50			164
Earnings Before Noncontrolling Interest and Income Tax		211		1		5		(59	)		158			(17	)		2		2		(28	)		(41	)
Noncontrolling Interest		—		—		—		(5	)		(5	)		—			—		—		(4	)		(4	)
Earnings Before Income Tax	$	211	$	1	$	5	$	(54	)	$	163		$	(17	)	$	2	$	2	$	(24	)	$	(37	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $211 million to the total company earnings before income tax in the nine months ended September 30, 2010 compared to $228 million in the nine months ended September 30, 2009.

CBM sales revenues were $454 million in the nine months ended September 30, 2010 compared to $444 million in the nine months ended September 30, 2009. The $10 million increase was primarily due to a 5.9% increase in volumes sold, offset, in part by a 3.6% decrease in average sales price per thousand cubic feet.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		67.7		63.9		3.8			5.9	%
Average CBM Sales price per thousand cubic feet	$	6.70	$	6.95	$	(0.25	)		(3.6	)%

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CBM sales volumes increased 3.8 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. Also, the 2009 period CBM volumes were lower by approximately 1.2 billion cubic feet of deferrals related to the idling of the Buchanan Mine throughout most of the 2009 period. The decrease in CBM 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 39.7 billion cubic feet of our produced CBM gas sales volumes for the nine months ended September 30, 2010 at an average price of $8.12 per thousand cubic feet. In the nine months ended September 30, 2009, these financial hedges represented approximately 36.4 billion cubic feet at an average price of $9.12 per thousand cubic feet. Although average market prices have increased slightly in the period-to-period comparison, we have sold more hedge volumes under lower average prices in the 2010 period compared to the 2009 period.

Total costs for the CBM gas segment were $243 million for the nine months ended September 30, 2010 compared to $216 million for the nine months ended September 30, 2009. Higher costs in the period-to-period comparison are primarily related to higher volumes sold and higher unit costs. Unit cost variances are explained below.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		67.7		63.9		3.8			5.9	%
Average CBM lifting costs per thousand cubic feet sold	$	0.57	$	0.56	$	0.01			1.8	%
Average CBM gathering costs per thousand cubic feet sold	$	1.09	$	1.00	$	0.09			9.0	%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.69	$	0.74	$	(0.05	)		(6.8	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.23	$	1.08	$	0.15			13.9	%

CBM lifting costs were $39 million in the nine months ended September 30, 2010 compared to $36 million in the nine months ended September 30, 2009. Average CBM lifting costs per unit were $0.57 per thousand cubic feet sold in the current period compared to $0.56 per thousand cubic feet in the prior period. Severance taxes were impaired due to average market sales price increasing, causing average unit costs for severance taxes to trend up. The increase in severance taxes is also related to Buchanan County, Virginia severance tax settlement that was finalized earlier this year which changed deductions allowable in the calculation of severance tax due when the price of gas falls between certain ranges. This increase was offset by salt water disposal cost improvements due to recycling the water produced from our wells to be used in hydraulic fracturing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Unit costs are also improved due to higher volumes sold resulting in fixed costs being spread over additional volumes, lowering the per unit costs.

CBM gathering costs were $74 million in the nine months ended September 30, 2010 compared to $64 million in the nine months ended September 30, 2009. The increase reflects additional volumes of 5.9% and a 9.0% increase in average CBM gathering costs unit costs. CBM unit costs were $1.09 per thousand cubic feet in the current period compared to $1.00 per thousand cubic feet in the prior period. Higher average CBM gathering unit costs are related to higher power charges and additional in-transit charges, offset, in part, by the impact of higher volumes on fixed charges. Power charges have increased in the period-to-period comparison due to higher utility rates being charged in the current year. In-transit charges have increased due to additional capacity of firm transportation being purchased after the 2009 period to assure delivery of additional volumes being produced.

General and administrative costs attributable to the Total Gas segment have increased approximately $12 million to $63 million in the nine months ended September 30, 2010 compared to $51 million in the nine months ended September 30, 2009. The increase was attributable to additional staffing and additional corporate service

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charges from CONSOL Energy. With the Dominion Acquisition which closed on April 30, 2010, the majority of the operational support personnel were retained. The additional employees are supporting the ramp up in the gas drilling program by providing various services. The acquisition also resulted in additional support charges from CONSOL Energy. These charges are primarily based on revenue and capital expenditures projections between coal and gas.

General and administrative costs for the CBM segment were $47 million in both the nine months ended September 30, 2010 and 2009. General and administrative costs attributable to the Total Gas segment are allocated to the individual gas segments based on a combination of production and employee counts. Although total general and administrative costs are higher in the period-to-period comparison, the percentage allocated to CBM is lower based on CBM production volumes to total gas volumes in the current period. The impact of higher volumes of CBM gas sold resulted in a decrease in unit costs in the period-to-period comparison. General and administrative costs were $0.69 per thousand cubic feet sold in the nine months ended September 30, 2010 compared to $0.74 per thousand cubic feet sold in the nine months ended September 30, 2009.

Depreciation, depletion and amortization attributable to the CBM segment was $83 million in the nine months ended September 30, 2010 compared to $69 million in the nine months ended September 30, 2009. There was approximately $64 million, or $0.95 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2010. The production portion of depreciation, depletion and amortization was $53 million, or $0.83 per unit-of-production in the nine months ended September 30, 2009. The CBM unit-of-production rate increased due to revised rates which are generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. The in-field drilling program and addition of the assets and related reserves acquired in the Dominion Acquisition caused the rate to increase due to the proportion of asset value to the proved or proved developed reserves. There was approximately $19 million, or $0.28 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the nine months ended September 30, 2010. The non production related depreciation, depletion and amortization was $16 million, or $0.25 per thousand cubic feet in the nine months ended September 30, 2009. The increase was related to additional gathering assets placed in service after the 2009 period.

CONVENTIONAL GAS SEGMENT

The conventional segment contributed a $1 million to the total company earnings before income taxes in the nine months ended September 30, 2010 compared to a loss of $1 million in the nine months ended September 30, 2009.

Conventional segment sales revenues were $78 million in the nine months ended September 30, 2010 compared to $6 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		15.9		1.3		14.6		1,123.1	%
Average Conventional Sales price per thousand cubic feet	$	4.90	$	4.84	$	0.06		1.2	%

Conventional sales volumes increased 14.6 billion cubic feet in the nine months ended September 30, 2010 compared to 2009 primarily due to the Dominion Acquisition. Approximately 95% of the acquired producing wells are conventional type wells. The increase in average sales price was the result of general market improvements.

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Total costs for the conventional segment were $77 million in the nine months ended September 30, 2010 compared to $7 million in the nine months ended September 30, 2009. The increase is attributable to additional volumes produced in the period and lower average unit costs. Conventional average unit costs have decreased due to the significant increase in volumes related to the additional production acquired in the Dominion Acquisition. A detailed analysis of cost categories is not meaningful due to the significant change in this segment related to the Dominion Acquisition and therefore will not be presented. General and administrative costs attributable to the total gas segment are allocated to the various gas segments based on a combination of production and employee counts. Conventional volumes are higher as a percent of total gas volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the conventional gas segment in the current period. See CBM segment discussion for explanation of total general and administrative costs. Depreciation, depletion and amortization costs per unit increased due to the additional assets acquired in the Dominion Acquisition.

	For the Nine Months Ended September 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		15.9		1.3		14.6			1,123.1	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.12	$	2.09	$	(0.97	)		(46.4	)%
Average Conventional gathering costs per thousand cubic feet sold	$	0.54	$	0.62	$	(0.08	)		(12.9	)%
Average Conventional general & administrative costs per thousand cubic feet sold	$	0.74	$	0.52	$	0.22			42.3	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.45	$	2.17	$	0.28			12.9	%

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $5 million to the total company earnings before income taxes in the nine months ended September 30, 2010 compared to $3 million in the three months ended September 30, 2009.

The Marcellus segment sales revenues were $34 million in the nine months ended September 30, 2010 compared to $15 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		7.0		3.5		3.5		100.0	%
Average Marcellus Sales price per thousand cubic feet	$	4.79	$	4.16	$	0.63		15.1	%

The increase in Marcellus average sales price is the result of an improvement in general market prices and various gas swap transactions that occurred in the three months ended September 30, 2010. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 0.4 billion cubic feet of our produced Marcellus gas sales volumes for the nine months ended September 30, 2010 at an average price of $5.05 per thousand cubic feet. There were no gas swap transactions for the Marcellus segment that occurred in the nine months ended September 30, 2009. The increase in sales volumes is primarily due to additional wells coming online from our on-going drilling program. At September 30, 2010, there were 45 Marcellus Shale wells in production including 17 wells acquired in the Dominion Acquisition. At September 30, 2009, there were 19 Marcellus Shale wells in production.

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Total costs for the Marcellus segment were $29 million in the nine months ended September 30, 2010 compared to $12 million in the nine months ended September 30, 2009. The increase was primarily due to the additional volumes sold.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		7.0		3.5		3.5		100.0	%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.46	$	0.13	$	0.33		253.8	%
Average Marcellus gathering costs per thousand cubic feet sold	$	1.08	$	1.04	$	0.04		3.8	%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.68	$	0.68	$	—		—
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.89	$	1.46	$	0.43		29.5	%

Marcellus lifting costs were $3 million in the nine months ended September 30, 2010 compared to $1 million in the nine months ended September 30, 2009. Average Marcellus lifting costs were $0.46 per thousand cubic feet sold in the current period compared to $0.13 per thousand cubic feet sold in the prior year period. Average Marcellus lifting cost per unit were higher in the 2010 period compared to the 2009 period primarily due to additional road maintenance and higher salt water disposal per unit costs. Higher road maintenance was related to additional number of wells in production in the period-to-period comparison requiring additional miles of road to be maintained. Higher salt water disposal per unit costs were related to higher volumes of water produced compared to the prior year period.

Marcellus gathering costs were $8 million in the nine months ended September 30, 2010 compared to $4 million in the nine months ended September 30, 2009. Average gathering costs per unit for Marcellus wells increased 3.8%, or $0.04, primarily due to additional power charges, additional contractual service charges and additional compression charges. Power charges have increased per unit due to higher rates being charged by the utilities. Additional contract service charges have been incurred in the period-to-period comparison primarily due to additional gathering lines in service that need maintained. Additional compression charges have been incurred primarily due to growing the Marcellus field in the period-to-period comparison requiring additional compression. These charges were offset, in part, by lower in-transit charges in the period-to-period comparison. Unused capacity charges for firm transportation are reflected in other corporate charges. The increases were also offset, in part, by the additional volumes sold resulting in fixed charges being spread over additional volumes.

General and administrative costs on the Marcellus gas segment were $5 million in the nine months ended September 30, 2010 compared to $2 million in the nine months ended September 30, 2009. General and administrative costs attributable to the Total Gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The total general and administrative cost increase in the period-to-period comparison was offset by higher volumes of Marcellus gas sold. General and administrative costs were $0.68 per thousand cubic feet sold in both the nine months ended September 30, 2010 and 2009. The Total Gas segment general and administrative cost increase was explained in the CBM segment.

Depreciation, depletion and amortization was $13 million in the nine months ended September 30, 2010 compared to $5 million in the three months ended September 30, 2009. There was approximately $12 million, or $1.72 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 nine months ended September 30, 2010. There was approximately $4 million, or $1.28 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 nine months ended September 30, 2009. 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. There was approximately $1 million, or $0.17 per thousand cubic feet per unit

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cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the nine months ended September 30, 2010. There was approximately $1 million, or $0.18 per thousand cubic feet per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the nine months ended September 30, 2009.

OTHER GAS SEGMENT

The Other gas segment includes activity not assigned to 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 production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $5 million in the nine months ended September 30, 2010 and $3 million in the nine months ended September 30, 2009. Total costs related to these other sales were $7 million in the 2010 period compared to $3 million in the 2009 period. The increase in costs in the period-to-period comparison was primarily attributable to depreciation, depletion and amortization. Higher depreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. The higher rate was due to an increase in the unit-of-production rates in 2010. The increase was related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. A per unit analysis of the other operating costs in Chattanooga is not meaningful due to the low volumes produced in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy 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 $47 million in the nine months ended September 30, 2010 compared to $30 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.9		7.3		2.6		35.6	%
Average Sales Price Per thousand cubic feet	$	4.69	$	4.07	$	0.62		15.2	%

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 $8 million in the nine months ended September 30, 2010 compared to $4 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)		1.5		1.0		0.5		50.0	%
Average Sales Price Per thousand cubic feet	$	5.65	$	4.16	$	1.49		35.8	%

Other income decreased $1 million in the nine months ended September 30, 2010 compared to 2009 due to various miscellaneous 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 CONSOL Energy 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

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period-to-period change. Royalty interest gas costs were $41 million in the nine months ended September 30, 2010 compared to $23 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.9		7.3		2.6		35.6	%
Average Cost Per thousand cubic feet	$	4.05	$	3.20	$	0.85		26.6	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas 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 $7 million in the nine months ended September 30, 2010 compared to $3 million in the nine months ended September 30, 2009.

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)		1.3		1.0		0.3		30.0	%
Average Cost Price Per thousand cubic feet	$	5.44	$	3.09	$	2.35		76.1	%

Exploration and other costs were $21 million in the nine months ended September 30, 2010 compared to $15 million in the nine months ended September 30, 2009. The $6 million increase in the period-to-period comparison was due to the following items:

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Dry hole and lease expiration costs	$	15	$	10	$	5		50.0	%
Land and Delay Rentals		3		3		—		—
Exploration		3		2		1		50.0	%
Total Exploration and Other Costs	$	21	$	15	$	6		40.0	%

Dry hole and lease expiration costs were $5 million higher primarily due to lease surrenders in the current period and additional dry wells in the period-to-period comparison.

Land and delay rentals were consistent in the period-to-period comparison.

Exploration costs have increased $1 million due to various transactions that have occurred throughout both periods, none of which were individually material.

Other corporate expenses were $40 million in the nine months ended September 30, 2010 compared to $22 million in the nine months ended September 30, 2009. The $18 million increase was due to the following items:

	For the Nine Months Ended September 30,
	2010		2009		Variance		Percent Change
Short-term incentive compensation	$	14	$	11	$	3		27.3	%
Stock-based compensation		11		8		3		37.5	%
Variable interest earnings		4		1		3		300.0	%
Legal fees		3		—		3		100.0	%
Bank fees		3		1		2		200.0	%
Other		5		1		4		400.0	%
Total Other Corporate Expenses	$	40	$	22	$	18		81.8	%

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The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit cost goals. Short-term incentive compensation expense is higher in the 2010 period compared to the 2009 period due to expected higher payouts.

Stock-based compensation is higher in the period-to-period comparison primarily due to the conversion of the CNX Gas long-term incentive compensation plan to CONSOL Energy restricted stock units in the nine months ended September 30, 2009. The conversion resulted in a reduction of approximately $4 million of expense in the nine months ended September 30, 2009. Additional expense is also related to stock-based compensation allocated from CONSOL Energy to the gas segment in the 2010 period. These increases were offset, in part, by the non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-in transaction. The expense previously recognized for these stock options was reversed on the gas segment. Stock-based compensation is now allocated from CONSOL Energy.

Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest, but guarantees bank loans the entity holds related to its purchases of drilling rigs. CONSOL Energy is also the main customer of the third party, and based on analysis is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact is fully reversed in the noncontrolling interest line discussed below.

Legal fees are related to expenses for the special committee formed during the CNX Gas take-in transaction. The fees also represent legal fees related to the shareholder litigation related to the transaction.

Bank fees are higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. The facility was amended to allow $700 million of borrowings and was extended through 2014.

Other corporate related expense increased $4 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

Interest expense related to the gas segment was $6 million in the nine months ended September 30, 2010 and the nine months ended September 30, 2009. Interest is incurred by the gas segment on the gas segment revolving credit facility, a capital lease and debt held by a variable interest entity. No significant changes in these components occurred 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 CONSOL Energy gas segment holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas segment has been determined to be the primary beneficiary due to guarantees of the third party’s bank debt related to their purchase of drilling rigs. The third party entity provides drilling services primarily to the CONSOL Energy gas segment. CONSOL Energy 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.

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Year-to-Date OTHER SEGMENT ANALYSIS for the nine months ended September 30, 2010 compared to the nine months ended September 30, 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 had a loss before income tax of $184 million in the nine months ended September 30, 2010 compared to a loss before income tax of $17 million in the nine months ended September 30, 2009. The other segment also includes total company income tax expense of $75 million in the nine months ended September 30, 2010 compared to $169 million in the nine months ended September 30, 2009.

	Nine Months Ended September 30,
	2010			2009			Variance			Percentage Change
Sales—Outside	$	220		$	198		$	22			11.1	%
Other Income		22			25			(3	)		(12.0	)%
Total Revenue		242			223			19			8.5	%
Cost of Goods Sold and Other Charges		269			200			69			34.5	%
Depreciation, Depletion & Amortization		14			15			(1	)		(6.7	)%
Interest Expense		134			17			117			688.2	%
Taxes Other Than Income Tax		9			8			1			12.5	%
Total Costs		426			240			186			77.5	%
Earnings Before Income Tax		(184	)		(17	)		(167	)		982.4	%
Income Tax		75			169			(94	)		(55.6	)%
Net Income	$	(259	)	$	(186	)	$	(73	)		39.2	%

Industrial supplies:

Total revenues from the industrial supply operations were $145 million in the nine months ended September 30, 2010 compared to $144 million in the nine months ended September 30, 2009. The increase was due primarily to additional sales volumes.

Total costs related to industrial supply sales were $144 million for the nine months ended September 30, 2010 compared to $138 million for the nine months ended September 30, 2009. The increase of $6 million was due primarily to changes in last-in-first-out valuations and additional sales volumes.

Transportation operation:

Total revenue from the transportation operations was $84 million in the nine months ended September 30, 2010 compared to $60 million in the nine months ended September 30, 2009. The increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Total costs related to the transportation operations were $60 million in the nine months ended September 30, 2010 compared to $51 million in the nine months ended September 30, 2009. The increase of $9 million was related to the additional thru-put handled by the operation.

Miscellaneous other:

Other income was $13 million in the nine months ended September 30, 2010 compared to $19 million in the nine months ended September 30, 2009. The decrease of $6 million was primarily attributable to lower gain on sales of assets and lower equity in earnings of affiliates. These decreases were offset, in part, by higher interest income and various miscellaneous transactions that have occurred throughout both periods, none of which were individually material.

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Other corporate costs include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $222 million in the nine months ended September 30, 2010 compared to $51 million in the nine months ended September 30, 2009. Other corporate costs increased $171 million due to the following.

• Financing and acquisition fees of $61 million were incurred in the nine months ended September 30, 2010 primarily related to the equity and debt issuance that raised approximately $4.6 billion dollars. These fees also include costs related to extending and amending the CONSOL Energy revolving credit facility, the Dominion Acquisition and the purchase of the CNX Gas noncontrolling interest.

• Interest expense was $134 million in the nine months ended September 30, 2010 compared to $17 million in the nine months ended September 30, 2009. The increase of $117 million was primarily related to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition.

• Bank fees were $11 million in the nine months ended September 30, 2010 compared to $4 million in the nine months ended September 30, 2009. The increase of $7 million is primarily related to the refinanced revolving credit facility.

• Fees related to disposing non-core assets of $2 million were incurred in the nine months ended September 30, 2010.

• Various other corporate items decreased $13 million primarily due to expenses recognized in conjunction with the 2009 cease use of the previous headquarters. The decrease was also attributable to various transactions that occurred throughout both periods, none of which were individually material.

• Severance payments of $3 million were incurred in the 2009 period related to various layoffs that were necessary due to the economic downturn that occurred.

Income Taxes:

The effective income tax rate was 22.9% in the nine months ended September 30, 2010 and 28.9% in the nine months ended September 30, 2009. The effective tax rate is sensitive to the relationship between pre-tax earnings and percentage depletion. The proportion of coal per-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 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 10-Q.

	For the Nine Months Ended September 30,
	2010			2009			Variance			Percent Change
Total Company Earnings Before Income Tax	$	329		$	586		$	(257	)		(43.9	)%
Income Tax Expense	$	75		$	169		$	(94	)		(55.6	)%
Effective Income Tax Rate		22.9	%		28.9	%		(6.0	)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied our working capital requirements and funded our capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On May 7, 2010, CONSOL Energy refinanced and extended the previous $1.0 billion credit facility to $1.5 billion, including borrowings and letters of credit, for a term of four years. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. The facility was expanded to meet the asset development needs of the company. The obligations under the credit agreement continue to be 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 due March 2012. Fees and interest rate

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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 2.00 to 1.00 through 2010, and no less than 2.50 to 1.00 thereafter, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 5.80 to 1.00 at September 30, 2010. The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00 thereafter, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CONSOL Energy and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 3.73 to 1.00 at September 30, 2010. The facility also includes a senior secured leverage ratio covenant of no more than 2.50 to 1.00 through 2010, and no more than 2.00 to 1.00 thereafter, measured quarterly. The senior secured leverage ratio covenant is calculated as the ratio of secured debt to EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on the revolving credit facility plus the CONSOL Energy Inc. 7.875% bonds due in March 2012. The senior secured leverage ratio was 0.75 to 1.00 at September 30, 2010. 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 company. At September 30, 2010, the facility had approximately $136 million drawn and $268 million of letters of credit outstanding, leaving $1,096 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy completed an equity offering on March 31, 2010 of 44.3 million shares of common stock, which generated net proceeds of approximately $1.8 billion. On April 1, 2010, CONSOL Energy issued $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020. Covenants in the Notes Indenture limit CONSOL Energy’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company. The equity and bond proceeds were used to complete the Dominion Appalachian E&P business acquisition for total consideration of approximately $3.475 billion. The acquisition closed on April 30, 2010.

The Pennsylvania Department of Environmental Protection (PA DEP) and CONSOL Energy have executed a Consent Order and Agreement (the Agreement) that addresses financial assurance required by the State for CONSOL Energy’s Pennsylvania mine water treatment facilities for mines closed prior to August 1977. The Agreement requires the company to post approximately $34 million of financial assurance over a 10-year time frame. CONSOL Energy obtained surety bonds to satisfy the initial obligation related to the Agreement.

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 million of short-term funding and letters of credit. Previously the facility provided up to $165 million. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivables. The facility was expanded to meet the future cash needs of the Company. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper rates plus a charge for administrative services paid to the financial institutions. At September 30, 2010, eligible accounts receivable totaled approximately $200 million. There was no subordinated retained interest at September 30, 2010. Accounts receivable totaling $200 million were reflected as Accounts Receivable—Securitized in Current Assets and Borrowings Under Securitization Facility in Current Liabilities on the consolidated balance sheet at September 30, 2010. There were no letters of credit outstanding against the facility at September 30, 2010.

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On May 7, 2010, CNX Gas, a fully consolidated subsidiary of CONSOL Energy, refinanced and extended the existing $200 million credit facility to $700 million, including borrowings and letters of credit, for a term of four years. The facility was expanded to meet the asset development needs of the company. The obligations under the credit agreement are secured by substantially all of the assets of CNX Gas and its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds due March 2012. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CNX Gas Corporation and certain of its subsidiaries. The interest coverage ratio was 86.73 to 1.00 at September 30, 2010. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CNX Gas Corporation and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas Corporation and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.28 to 1.00 at September 30, 2010. Covenants in the facility limit our ability to dispose of assets, make investments, pay dividends and merge with another company. At September 30, 2010, the facility had approximately $78 million drawn and $15 million of letters of credit outstanding, leaving $607 million of unused capacity.

In May 2010, CONSOL Energy completed a tender offer to acquire the 25.3 million shares of CNX Gas common stock and vested stock options that it did not currently own for $38.25 per share. The aggregate purchase price was $991 million. CNX Gas is now a wholly-owned subsidiary of CONSOL Energy. CNX Gas was designated a subsidiary guarantor under the 2017 and 2020 CONSOL Energy Notes Indenture. CNX Gas has to comply with the covenants in the Notes Indenture, which limit the company’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company.

In September 2010, CONSOL Energy refinanced approximately $103 million of industrial development bonds associated with its wholly-owned CNX Marine Terminal in the Port of Baltimore, Maryland. The refunding municipal bonds issued by the Maryland Economic Development Corporation mature on September 1, 2025 and carry an interest rate of 5.75%. The previous bonds carried an interest rate of 6.50% and were due to mature in December 2010 and October 2011.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit, potential counterparty defaults, and further commercial bank failures. Financial market disruptions may impact our collection of trade receivables. CONSOL Energy constantly monitors the creditworthiness of our customers. We believe that our current group of customers are sound and represent no abnormal business risk.

CONSOL Energy believes that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy our working capital requirements, debt service obligations, to fund planned capital expenditures or pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow

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hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was an asset of $108 million at September 30, 2010. The ineffective portion of these contracts was insignificant to earnings in the nine months ended September 30, 2010. Hedge counterparties consists of commercial banks who participate or have been past participants in the revolving credit facility. No issues related to our hedge agreements have been encountered to date.

CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions primarily with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt financing. There can be no assurance that additional capital resources, including debt financing, will be available to CONSOL Energy on terms which CONSOL Energy finds acceptable, or at all.

Cash Flows (in millions)

	Nine Months Ended September 30,
	2010			2009			Change
Cash flows from operating activities	$	879		$	728		$	151
Cash used in investing activities	$	(5,255	)	$	(615	)	$	(4,640	)
Cash provided by (used in) financing activities	$	4,326		$	(219	)	$	4,545

Cash flows from operating activities changed primarily due to the following items:

• Operating cash flows increased due to coal inventories. Coal inventories decreased 1.0 million tons in the nine months ended September 30, 2010 compared to increasing 1.5 million tons in the nine months ended September 30, 2009.

• Operating cash flow increased due to various changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years.

• Operating cash flow decreased in 2010 due to lower net income attributable to CONSOL Energy shareholders in the period-to-period comparison.

Net cash used in investing activities changed primarily due to the following items:

• On April 30, 2010, CONSOL Energy paid $3.474 billion to acquire the Dominion Appalachian E&P business. See Note 2—“Acquisitions and Dispositions” in the Consolidated Financial Statements for additional details.

• On May 28, 2010, CONSOL Energy paid $991 million to acquire the shares of CNX Gas common stock which it did not previously own.

• Total capital expenditures increased $133 million to $822 million in 2010 compared to $689 million in 2009. Capital expenditures for coal and other activities increased $104 million due to various projects including the purchase of various coal lands, additional equipment at various mining locations, continued work on longwall face extensions at various locations, and the Buchanan water handling system. Capital expenditures for the gas segment increased $29 million due to the drilling program in the nine months ended September 30, 2010.

• Proceeds from the sale of assets were $25 million in 2010 compared to $70 million in 2009. Proceeds in both periods were primarily related to the sale leaseback of various mining equipment.

Net cash provided by (used in) financing activities changed primarily due to the following items:

• Proceeds of $2.8 billion were received on April 1, 2010 in connection with the issuance of $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.

• Proceeds of $1.8 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.

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• In 2010, CONSOL Energy paid outstanding borrowings of $279 million under the revolving credit facility. In 2009, CONSOL Energy paid outstanding borrowings of $148 million under the revolving credit facility.

• In 2010, CNX Gas, a 100% owned subsidiary, received $20 million of proceeds from the revolving credit facility. In 2009, the activity on the revolving credit facility was minimal.

• In 2010, CONSOL Energy received $150 million of proceeds from the accounts receivable securitization facility. This facility which has been increased to $200 million, was fully drawn at September 30, 2010. There were no proceeds or payments under this facility in the months ended September 30, 2009.

The following is a summary of our significant contractual obligations at September 30, 2010 (in thousands):

	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	213,900	$	—	$	—	$	—	$	213,900
Borrowings Under Securitization Facility		200,000		—		—		—		200,000
Purchase Order Firm Commitments		135,809		223,825		29,925		—		389,559
Gas Firm Transportation		37,517		71,432		62,192		318,960		490,101
Long-term Debt		8,349		262,434		5,031		2,873,593		3,149,407
Interest on Long-term Debt		249,359		469,924		460,173		838,209		2,017,665
Capital (Finance) Lease Obligations		7,568		11,771		9,438		36,082		64,859
Interest on Capital (Finance) Lease Obligations		4,497		7,447		6,058		8,771		26,773
Operating Lease Obligations		87,006		141,412		104,764		168,633		501,815
Other Long-term Liabilities (a)		570,844		605,602		597,495		2,493,422		4,267,363
Total Contractual Obligations (b)	$	1,514,849	$	1,793,847	$	1,275,076	$	6,737,670	$	11,321,442

(a) Long-term liabilities include other post-employment benefits, work-related injuries and illnesses, mine reclamation and closure and other long-term liability costs. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2010 contributions are expected to approximate $72 million.

(b) The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

Debt

At September 30, 2010, CONSOL Energy had total long-term debt of $3,214 million outstanding, including the current portion of long-term debt of $16 million. This long-term debt consisted of:

• An aggregate principal amount of $1.5 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

• An aggregate principal amount of $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

• An aggregate principal amount of $250 million of 7.875% notes due in March 2012. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and premium, if any, and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries. The notes are senior secured obligations and rank equally with all other secured indebtedness of the guarantors.

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• An aggregate principal amount of $103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025.

• $35 million in advance royalty commitments with an average interest rate of 7.36% per annum.

• An aggregate principal amount of $11 million on a variable rate note due in December 2012 that bears interest at 6.10% at September 30, 2010. This note was incurred by a variable interest entity that is fully consolidated in which CONSOL Energy holds no ownership interest.

• An aggregate principal amount of $65 million of capital leases with a weighted average interest rate of 6.63% per annum.

At September 30, 2010, CONSOL Energy also had $136 million of aggregate principal amounts of outstanding borrowings and approximately $268 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At September 30, 2010, CONSOL Energy had $200 million of borrowings under the securitization facility.

At September 30, 2010, CNX Gas, a wholly owned subsidiary, had $78 million of aggregate principal amounts of outstanding borrowings and approximately $15 million of letters of credit outstanding under its $700 million secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $3,098 million at September 30, 2010 and $2,024 million at December 31, 2009. Total equity increased primarily due to the sale of approximately 44.3 million shares of common stock which resulted in net proceeds of approximately $1.8 billion. Total equity also increased due to net income attributable to CONSOL Energy shareholders for the nine months ended September 30, 2010. These increases were offset, in part, by the acquisition of the minority interest in CNX Gas and the declaration of dividends. See the Consolidated Statements of Stockholders’ Equity for additional details.

Dividend information for the current year to date is as follows:

Declaration Date	Amount Per Share		Record Date	Payment Date
November 1, 2010	$	0.10	November 12, 2010	November 26, 2010
July 30, 2010	$	0.10	August 13 2010	August 23, 2010
April 30, 2010	$	0.10	May 10, 2010	May 20, 2010
January 29, 2010	$	0.10	February 9, 2010	February 19, 2010

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 3.73 to 1.00 and our availability was approximately $1,096 million at September 30, 2010. The credit facility does not permit dividend payments in the event of default. The indenture to the 2017 and 2020 notes limits dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt under the indentures and other payment limitations. There were no defaults in the nine months ended September 30, 2010.

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Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at September 30, 2010. The various multi-employer benefit plans are discussed in Note 17-“Other “Employee Benefit Plans” of the consolidated financial statements and related notes for the year ended December 31, 2009 included in exhibit 99.1 of CONSOL Energy’s Form 8-K filed on September 21, 2010. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the balance sheet at September 30, 2010. Management believes these items will expire without being funded. See Note 11-“Commitments and Contingent Liabilities” for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Recent Accounting Pronouncements

In April 2010, the Financial Accounting Standards Board issued an update to the Extractive Activities – Oil and Gas Topic of the FASB Accounting Standards Codification which is intended to revise definitions due to SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. We believe adoption of this new guidance will not have a material impact on CONSOL Energy’s financial statements.

Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

• the continued weakness in global economic conditions, in any industry in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;

• an extended decline in prices we receive for our coal and gas affecting our operating results and cash flows;

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• reliance on customers honoring existing contracts, extending existing contracts or entering into new long-term contracts for coal;

• reliance on major customers;

• our inability to collect payments from customers if their creditworthiness declines;

• the disruption of rail, barge and other systems that deliver our coal;

• a loss of our competitive position because of the competitive nature of the coal and gas industry, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;

• our inability to hire qualified people to meet replacement or expansion needs;

• our inability to maintain satisfactory labor relations;

• coal users switching to other fuels in order to comply with various environmental standards related to coal combustion;

• the inability to produce a sufficient amount of coal to fulfill our customers’ requirements which could result in our customers initiating claims against us;

• foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;

• the risks inherent in coal mining being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, accidents and weather conditions which could impact financial results;

• increases in the price of commodities used in our mining operations could impact our cost of production;

• obtaining governmental permits and approvals for our operations;

• the effects of proposals to regulate greenhouse gas emissions;

• the effects of government regulation;

• the effects of stringent federal and state employee health and safety regulations;

• the effects of mine closing, reclamation and certain other liabilities;

• uncertainties in estimating our economically recoverable coal and gas reserves;

• the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;

• increased exposure to employee related long-term liabilities;

• minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;

• lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan;

• our ability to comply with laws or regulations requiring that we obtain surety bonds for workers’ compensation and other statutory requirements;

• acquisitions that we recently have made or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made, including with respect to the Dominion Acquisition;

• the anti-takeover effects of our rights plan could prevent a change of control;

• risks in exploring for and producing gas;

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• new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

• the disruption of pipeline systems which deliver our gas;

• the availability of field services, equipment and personnel for drilling and producing gas;

• replacing our natural gas reserves which if not replaced will cause our gas reserves and gas production to decline;

• costs associated with perfecting title for gas rights in some of our properties;

• other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties;

• our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental rules;

• the coalbeds and other strata from which we produce methane gas frequently contain impurities that may hamper production;

• the enactment of severance tax on natural gas in states in which we operate may impact results of existing operations and impact the economic viability of exploiting new gas drilling and production opportunities;

• location of a vast majority of our gas producing properties in three counties in southwestern Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area;

• our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

• other factors discussed in our 2009 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy’s exposure to the risks of changing natural gas prices, interest rates and foreign exchange rates.

CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOL Energy uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy prohibits the use of derivatives for speculative purposes.

CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. Derivative instruments are used primarily to mitigate uncertainty and volatility and cover underlying exposures. CONSOL Energy’s market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

CONSOL Energy believes that the use of derivative instruments, along with the risk assessment procedures and internal controls, mitigates our exposure to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy results of operations depending on interest rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

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For a summary of accounting policies related to derivative instruments, see Note 1 of the Notes to the Consolidated Financial Statements and related notes for the year ended December 31, 2009 included in exhibit 99.1 of CONSOL Energy’s Form 8-K filed on September 21, 2010.

Sensitivity analysis of the incremental effects on pre-tax income for the nine months ended September 30, 2010 of a hypothetical 10 percent and 25 percent change in natural gas prices for open derivative instruments as of September 30, 2010 are provided in the following table:

	Incremental Decrease in Pre-tax Income Assuming a Hypothetical Price Change of:
	10%		25%
	(in millions)
Natural Gas (a)	$	22.1	$	55.3

(a) CONSOL Energy remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be offset by price changes in the underlying hedged item. CONSOL Energy entered into derivative instruments to convert the market prices related portions of the 2010 through 2012 anticipated sales of natural gas to fixed prices. The sensitivity analysis reflects an inverse relationship between increases in commodity prices and a benefit to earnings. We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At September 30, 2010, CONSOL Energy had $3,214 million aggregate principal amount of debt outstanding under fixed-rate instruments and $414 million aggregate principal amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were $136 million of borrowings outstanding at September 30, 2010. CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 2.56% per annum during the nine months ended September 30, 2010. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly decreased net income for the period. CONSOL Energy’s subsidiary, CNX Gas, also had outstanding borrowings under its revolving credit facility which bears interest at a variable rate. CNX Gas’ facility had outstanding borrowings of $78 million at September 30, 2010 and bore interest at a weighted average rate of 2.15% per annum during the nine months ended September 30, 2010. Due to the level of borrowings against this facility and the low weighted average interest rate in the nine months ended September 30, 2010, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income for the period.

Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.

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Hedging Volumes

As of October 19, 2010, our hedged volumes for the periods indicated are as follows:

	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2010 Fixed Price Volumes
Hedged Mcf		12,989,691		13,603,093		13,550,883		11,913,085		52,056,752
Weighted Average Hedge Price/Mcf	$	8.76	$	8.15	$	7.39	$	6.18	$	7.65
2011 Fixed Price Volumes
Hedged Mcf		5,567,010		5,628,866		5,690,722		5,690,722		22,577,320
Weighted Average Hedge Price/Mcf	$	6.84	$	6.84	$	6.84	$	6.84	$	6.84
2012 Fixed Price Volumes
Hedged Mcf		3,752,577		3,752,577		3,793,814		3,793,814		15,092,782
Weighted Average Hedge Price/Mcf	$	6.84	$	6.84	$	6.84	$	6.84	$	6.84

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2010 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal controls over financial reporting. There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The first through the nineteenth paragraphs of Note 11—“Commitments and Contingencies” in the notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 5. OTHER INFORMATION

Mine Safety and Health Administration Safety Data

We believe that CONSOL Energy is one of the safest mining companies in the world. The Company has in place health and safety programs that include extensive employee training, accident prevention, workplace inspection, emergency response, accident investigation, regulatory compliance and program auditing. The objectives of our health and safety programs are to eliminate workplace incidents, comply with all mining-related regulations and provide support for both regulators and the industry to improve mine safety.

The operation of our mines is subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. We present information below regarding certain mining safety and health citations which MSHA has issued with respect to our coal mining operations. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed.

During the three months ended September 30, 2010, neither CONSOL Energy’s mining complexes nor its closed and/or idled mines: (i) were assessed any Mine Act section 110(b)(2) penalties for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., a reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury); (ii) received any Mine Act section 107(a) imminent danger orders to immediately remove miners; or (iii) received any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern. In addition, there was one fatality at the Loveridge mine during the three months ended September 30, 2010.

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The table below sets forth by mining complex the total number of citations and/or orders issued by MSHA to CONSOL Energy and its subsidiaries under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments, received during the three months ended September 30, 2010 and legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes.

Name of Mine or Mining Complex(1)(2)	Mine Act Section 104 Significant & Substantial Citations(3)		Mine Act Section 104(b) Orders(4)	Mine Act Section 104(d) Citations & Orders(5)	Total Dollar Value of Proposed MSHA Assessments(6) (in thousands)		Number of Legal Actions Pending Before the Federal Mine Safety and Health Review Commission(7)
Enlow Fork		17	—	—	$	266		34
Bailey		32	—	—	$	73		23
McElroy		100	—	2	$	329		26
Shoemaker		58	3	3	$	46		7
Loveridge		56	—	2	$	355		12
Robinson Run		64	—	1	$	79		20
Blacksville #2		55	—	4	$	113		20
Buchanan		70	—	—	$	283		17
AMVEST - Fola Complex		9	—	—	$	18		4
Miller Creek Complex		10	—	—	$	39		3
Emery		8	—	—	$	86		15

(1) MSHA assigns an identification number to each coal mine and may or may not assign separate identification numbers to related facilities such as preparation plants. We are providing the information in the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.

(2) We have not included currently closed or idled mines in the above table. Our closed and/or idled mines did not receive any of the indicated citations in the three months ended September 30, 2010. Total proposed assessments were $134 in the three months ending September 30, 2010. There were 13 legal actions in total pending before the Federal Mine Safety and Health Review Commission for our closed and/or idle mines. These actions may have been initiated in prior quarters.

(3) Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.

(4) Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.

(5) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(6) Includes proposed MSHA assessments received during the three months ended September 30, 2010 for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7) Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.

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ITEM 6. EXHIBITS

Exhibit Index

3.2	Amended and Restated Bylaws of CONSOL Energy Inc., incorporated by reference to Exhibit 3.2 to Form 8-K filed on September 22, 2010.
3.2.1	Amended and Restated Bylaws of CONSOL Energy Inc. (marked to show changes to former bylaws), incorporated by reference to Exhibit 3.2.1 to Form 8-K filed on September 22, 2010.
10.1	Consulting Agreement by and between CONSOL Energy Inc. and John Whitmire, dated as of July 1, 2010.
10.2	Summary of Non-Employee Director Compensation.
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101	Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2010 furnished in XBRL)

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed. In accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission, Exhibit 101 is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities and Exchange Act of 1934, and otherwise is not subject to liability under these sections.

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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 thereunto duly authorized.

Dated: November 1, 2010

CONSOL ENERGY INC.
By:	/S/    J. BRETT HARVEY
	J. Brett Harvey
	Chairman of the Board, President and Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)
By:	/S/    WILLIAM J. LYONS
	William J. Lyons
	Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial and Accounting Officer)

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EX-10.1

Exhibit 10.1

Execution Copy

CONSULTING AGREEMENT

This Consulting Agreement (“Agreement”) is made effective as of July 1, 2010, by and between CONSOL Energy Inc., a Delaware corporation, CNX Center, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317 (“CONSOL” or the “Company”), and John Whitmire, an individual (the “Consultant”). Unless otherwise stated in this Agreement, the term “Company” includes the subsidiaries and affiliates of CONSOL Energy Inc.

1. Term

The term of this Agreement shall be for the period of twelve (12) months commencing July 1, 2010 and terminating on June 30, 2011, subject to the terms and conditions of this Agreement and unless terminated earlier in accordance with paragraph 11 herein (the “Term”); provided, however, that commencing on July 1, 2011 and on each anniversary thereafter, the Term shall be automatically extended for an additional one-year period (each a “Renewal Term”), subject to the terms and conditions of this Agreement and unless terminated earlier in accordance with paragraph 11 herein. For purposes of clarity, each Term or Renewal Term shall be for a one-year period.

2. Services

During the term of this Agreement, the Consultant shall perform the services defined in Exhibit A, entitled “Scope of Work”, which is attached hereto and made a part hereof. The Company and Consultant, by mutual agreement, may alter, amend or supplement the Scope of Work. The Consultant shall control the location, time, method and process by which he performs the services and accomplishes the tasks in the Scope of Work provided he meets established deadlines and, where possible, schedule the performance of the Consultant’s services in conjunction with Company employees to minimize scheduling conflicts. The Consultant will personally perform the services provided for herein.

3. Payments

During the term of this Agreement and subject to this Agreement’s terms, CONSOL shall pay the Consultant $725,000 per year, payable in equal monthly installments in arrears, for the performance of the services set forth in the Scope of Work (the “Annual Payment”). The Company shall make available reasonable and necessary clerical support to the Consultant at an annual cost not to exceed $50,000.

In addition, the Consultant shall be reimbursed for all actual reasonable, customary and usual out-of-pocket business-related expenses (“Expenses”) incurred on behalf of the Company, after submission and approval of invoices or expense reports, which shall be submitted monthly. To the extent that any reimbursements under this Agreement are taxable reimbursements, any such reimbursements payable to the Consultant shall be paid no later than December 31 of the year following the year in which the expense was incurred; provided, that the amount of expenses reimbursed in one year shall not affect the amount eligible for reimbursement in any subsequent year and the Consultant’s right to reimbursement under this Agreement will not be subject to liquidation or exchange for another benefit.

In the event the Agreement is terminated by the Consultant, is terminated by the Company for Cause (as defined below), or the Consultant dies or is disabled to the point that he can no longer provide the services in the Scope of Work, the Company shall only pay (i) the pro rata portion of the Annual Payment for services through the end of the month in which termination occurs, and (ii) any Expenses incurred through the date of termination.

In the event the Agreement is terminated by the Company other than for Cause, the Company shall pay (i) the pro rata portion of the Annual Payment earned for services performed through the date of termination plus (if the Consultant executes, and does not revoke, a general release of claims (excluding any claims arising under or in respect of Consultant’s rights under Section 10 of this Agreement) mutually acceptable to both parties and delivers the release to the Company on or before the 52^nd day following the termination date) the balance of the Annual Payment, if any, that would have otherwise been paid during the Term or Renewal Term, as the case may be, if the Agreement had not been terminated, and (ii) any Expenses incurred by the Consultant through the date of termination. For purposes of this Agreement, “Cause” means material breach of this Agreement by the Consultant, provided that to the extent curable such breach continues unabated for 20 days after receipt by Consultant of written notice from the Company containing a reasonable description of the alleged continuing material breach by Consultant.

No amounts other than those payable under this paragraph 3 shall be payable by the Company to the Consultant as compensation for the services provided by Consultant in accordance with this Agreement and the Consultant shall not qualify for any Company-provided employee benefits by virtue of this Agreement (other than those benefits provided to the Consultant pursuant to his membership on the CONSOL Board of Directors).

4. Independent Contractor

In the performance of services hereunder, the Consultant shall at all times be acting as an independent contractor and not as an employee, servant or agent of the Company, and the Company will have no right to determine or control the details, means or methods by which the Consultant performs his services or, except as provided in paragraph 2 and Exhibit A, the particular hours or days or number of hours or days of work. The Consultant shall have no power or authority to commit, bind or incur any obligation on behalf of the Company except as outlined in writing by CONSOL’s Chief Executive Officer or his designated representative and then only as may be necessary or appropriate in connection with the performance of the Consultant’s services pursuant to this Agreement.

5. Confidentiality and Ownership of Work Product

During the term of this Agreement and thereafter, all documents, data and other information which have not been made public and which come into the Consultant’s possession or attention from the Company in the course of his rendition of services under this Agreement shall be the Company’s sole property and shall not be used by the Consultant, except as may be necessary in the rendition of such services. Such documents, data and other information shall not be released or disclosed by the Consultant to anyone without the Company’s written consent (except where required by applicable laws, rules, regulations, court order or subpoena, copies of which shall be timely furnished to the Company prior to release or disclosure).

All reports, documents, data, presentations and other material prepared by the Consultant in the course of the performance of services pursuant to this Agreement shall be and remain the Company’s sole property in which the Consultant shall have no proprietary rights (including, but not limited to, copyright). The provisions of this paragraph shall survive and be binding upon the Consultant after termination of this Agreement. The Consultant shall, at the termination of this Agreement for any reason or upon a request from the Company, return or, as the case may be, provide such documents, data and other material referred to herein, including any copies or summaries thereof, to the Company.

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6. Non-Compete

Except as otherwise provided below, during the term of this Agreement, the Consultant shall not provide services (including, but not limited to, consulting, advising or employment) to any Competing Business. Also, during the term of this Agreement and for a period of two (2) years thereafter, the Consultant will not: directly or indirectly engage in a Competing Business, including, but not limited to, as an officer, director, proprietor, employee, partner, investor (other than as a holder of less than 1% of the outstanding capital stock of a publicly traded entity or an investment in any private business in which the investment of Consultant is less than $500,000), consultant, advisor, agent or sales representative, in any geographic region in which the Company offers products or services or conducts, has conducted or is planning to conduct business. A “Competing Business” shall be one that offers or is preparing to offer any products or services that are the same as or similar to or in competition with any of the products or services then offered by or then being prepared to be offered by any line of business of the Company. The Consultant’s services as a director on the boards of directors of Transocean Inc. and El Paso Corporation are expressly excluded from the provisions of this paragraph 6.

The Consultant acknowledges that the restrictions set forth in this paragraph 6 are reasonable because the Company offers its products and services and/or plans to offer its products and services in a broad, changing geographic market. The Consultant further covenants and agrees that the geographic, length of term and types of activities restricted contained in this Agreement are reasonable and necessary to protect the legitimate business interests of the Company because of the scope of the Company’s business. In the event that a court of competent jurisdiction shall determine that one or more of the provisions of this paragraph 6 is so broad as to be unenforceable, then such provision shall be deemed to be reduced in scope or length, as the case may be, to the extent required to make this paragraph enforceable. If the Consultant violates the provisions of this paragraph 6, the periods described herein shall be extended by that number of days which equals the aggregate of all days during which at any time any such violations occurred.

7. Non-Disparagement

The Consultant agrees not to disparage the services, products, customers, directors or employees of the Company during the term of the Agreement and for two years thereafter.

8. Representations, Warranties and Covenants

The Consultant covenants that the services performed hereunder will be performed in all material respects in accordance with any statutes, regulations, ordinances or contracts applicable to the services covered hereunder, and will be performed in all material respects in accordance with sound technical principles and prudent business custom and usage.

The Consultant further represents and warrants that he is not an official, employee or representative of any government or of any department, agency or instrumentality of any government or official, representative, agent or candidate of any political party and covenants that he shall not become such during the term of this Agreement.

9. Taxes

The Consultant shall be responsible for and pay any and all taxes or charges assessed against him or for which he is liable in connection with his performance of services hereunder and the receipt of the Annual Payment from the Company for such services, including, but not limited to, federal, state or local income

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taxes, social security, unemployment, Medicare, and agrees to indemnify the Company and hold the Company harmless against any and all claims or liability for income, corporation, excess profits, and other taxes or withholdings, and fines, penalties and interest thereon assessed or levied by the government of the United States or any state or local government, or by the government of any other country or any political subdivision thereof against the Consultant or against the Company for or on account of any remuneration made to or earned by the Consultant hereunder.

10. Indemnity

The Company shall indemnify, defend and hold harmless the Consultant for any damages or losses claimed by a third party, except to the extent that the Consultant is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from the Consultant’s gross negligence, willful misconduct or fraud. The provisions of this paragraph shall survive and be binding upon the Company after termination of this Agreement. This paragraph does not apply to tax liability.

11. Termination

The results of the Consultant’s services shall be subject to the Company’s review and approval. Notwithstanding paragraph 1 of this Agreement, the Company or the Consultant shall have the right to terminate this Agreement at any time and for any reason by giving thirty (30) days written notice to the other party. The Company may terminate this Agreement immediately for Cause, and this Agreement shall terminate immediately if the Consultant dies or becomes disabled.

12. Waiver

The failure of either party hereto to enforce any right under this Agreement shall not be construed to be a waiver of that right, or of damages caused thereby, or of any other rights under this Agreement.

13. Assignment

The Consultant shall not assign or transfer his rights and obligations under this Agreement without the prior written consent of the Company and any such unauthorized assignment or transfer shall be void and of no effect. The Company may assign this Agreement without the Consultant’s consent.

14. Applicable Law

This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to its conflict or choice of law provisions.

15. Scope of this Agreement

This Agreement constitutes the entire agreement between the Company and the Consultant as to the subject matter described herein. This Agreement may not be changed in any way except by written instrument signed by both the Company and the Consultant. Notwithstanding the foregoing or any provision of this Agreement to the contrary, the Company may at any time (without the consent of the Consultant) modify, amend or terminate any or all of the provisions of this Agreement or take any other action, to the extent necessary or advisable, to conform the provisions of this Agreement or the benefits provided thereunder with Section 409A of the Code, the regulations issued thereunder or an exception thereto.

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16. Code Section 409A

The provisions of this Agreement will be administered, interpreted and construed in a manner intended to comply with Section 409A (“Section 409A”) of the Internal Revenue Code of 1986, as amended (the “Code”), the regulations issued thereunder or any exception thereto. Notwithstanding anything in this Agreement to the contrary, any compensation that is designated under this Agreement as payable upon the Consultant’s termination of service or this Agreement shall be payable only upon the Consultant’s “separation from service” with the Company within the meaning of Section 409A and, except as provided below, any such compensation or benefits shall not be paid, or, in the case of installments, shall not commence payment, until the sixtieth (60th) day following the Consultant’s separation from service. Any installment payments that would have been made to the Consultant during the sixty (60) day period immediately following the Consultant’s separation from service but for the preceding sentence shall be paid to the Consultant on such sixtieth (60th) day and the remaining payments shall be made as provided in this Agreement. For purposes of this Agreement, the right to receive a payment, including each monthly installment payment, shall be treated as a right to receive a separate payment and, accordingly, each installment payment shall at all times be considered a separate and distinct payment as permitted under Section 409A. The Consultant shall have no right to designate the date of any payment under this Agreement. The Company reserves the right to accelerate and/or defer any payment to the extent permitted and consistent with Section 409A or an exception thereto. Notwithstanding any provision of this Agreement to the contrary, to the extent that a payment hereunder is subject to Section 409A of the Code (and not excepted therefrom) and payable on account of a separation from service, such payment shall be delayed for a period of six months after the date of termination (or, if earlier, the death of the Consultant) if the Consultant is a “specified employee” (as defined in Section 409A of the Code and determined in accordance with the procedures established by the Company). Any payment that would otherwise have been due or owing during such six-month period will be paid immediately following the end of the six-month period in the month following the month containing the six-month anniversary of the date of termination.

Notwithstanding any provision of this Agreement to the contrary, the Consultant acknowledges and agrees that the Company shall not be liable for, and nothing provided or contained in this Agreement will be construed to obligate or cause the Company to be liable for, any tax, interest or penalties imposed on the Consultant related to or arising with respect to this Agreement, including any violation of Code Section 409A, whether such violation arises under this Agreement or any other arrangement.

5

[Signature Page for Consulting Agreement with John Whitmire]

IN WITNESS WHEREOF, the Company and the Consultant have caused this Agreement to be executed as of the day and year first above written.

CONSOL ENERGY INC.

J. Brett Harvey

Chairman, President and Chief Executive Officer

Date:

CONSULTANT

John Whitmire

Date:

6

Exhibit A

SCOPE OF WORK AND TITLE

The scope of services to be provided by the Consultant is as follows:

• Providing high-level strategic advice to the Chief Executive Officer or such other executive as the Company may reasonably request.

• Providing market analysis and recommendations.

• Providing any other services as reasonably requested by the Company and agreed to by Consultant.

* It is expected that the Consultant will spend approximately 20% of his working time in providing the foregoing services.

A-1

EX-10.2

Exhibit 10.2

Non-Employee Director Compensation

Element of Compensation	Dollar Value
Annual Board Retainer:	$	95,000
Annual Lead Independent Director Retainer:	$	25,000
Annual Committee Chair Retainer (other than Audit Committee):	$	10,000
Annual Audit Committee Chair Retainer:	$	17,500
Annual Audit Committee Member Retainer (other than Audit Committee Chair):	$	10,000
Annual Equity Award:	$	130,000	(in restricted stock units)

Stock Ownership Guidelines: Each director must hold three (3) times the “Annual Board Retainer” in CONSOL Energy Inc.’s common stock (including any securities convertible or exercisable into its common stock (excluding stock options)) after five (5) years of service on the Board.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, J. Brett Harvey, certify that:

1. I have reviewed this report on Form 10-Q of CONSOL Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2010

/s/ J. Brett Harvey

J. Brett Harvey

Chairman of the Board, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, William J. Lyons, certify that:

1. I have reviewed this report on Form 10-Q of CONSOL Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2010

/s/ William J. Lyons

William J. Lyons

Chief Financial Officer and Executive Vice President

(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,

18 U.S.C. Section 1350

I, J. Brett Harvey, President and Chief Executive Officer (principal executive officer) of CONSOL Energy Inc. (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended September 30, 2010, of the Registrant (the “Report”):

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 1, 2010

/s/ J. Brett Harvey

J. Brett Harvey

Chairman of the Board, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,

18 U.S.C. Section 1350

I, William J. Lyons, Chief Financial Officer (principal financial officer) of CONSOL Energy Inc. (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended September 30, 2010, of the Registrant (the “Report”):

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 1, 2010

/s/ William J. Lyons

William J. Lyons

Chief Financial Officer and Executive Vice President