CNX 10-Q Quarterly Report June 30, 2011

CNX RESOURCES CORP

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10-Q 1 cnx-63011x10q.htm FORM 10-Q CNX-6.30.11-10Q

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 June 30, 2011



o	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 o

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 o

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 o Non-accelerated filer o Smaller Reporting Company o

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

Yes o 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 July 19, 2011
Common stock, $0.01 par value		226,743,672

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2011 and 2010	3
	Consolidated Balance Sheets at June 30, 2011 and December 31, 2010	4
	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2011	6
	Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010	7
	Notes to Unaudited Consolidated Financial Statements	8

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	86

ITEM 4.	Controls and Procedures	87

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	88

ITEM 5.	Other Information	88

ITEM 6.	Exhibits	91

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					Six Months Ended
	June 30,					June 30,
	2011		2010			2011		2010
Sales—Outside	$	1,486,000	$	1,220,116		$	2,871,478	$	2,389,630
Sales—Gas Royalty Interests	16,273		14,151			35,108		28,490
Sales—Purchased Gas	1,162		1,740			2,142		4,756
Freight—Outside	59,572		28,075			96,440		59,275
Other Income	24,921		25,265			48,137		47,256
Total Revenue and Other Income	1,587,928		1,289,347			3,053,305		2,529,407
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	927,399		818,771			1,741,108		1,585,633
Acquisition and Financing Fees	—		17,515			—		64,078
Loss on Debt Extinguishment	16,090		—			16,090		—
Gas Royalty Interests Costs	14,366		11,528			31,173		23,725
Purchased Gas Costs	1,776		1,339			2,452		3,647
Freight Expense	59,572		28,075			96,251		59,275
Selling, General and Administrative Expenses	43,423		39,045			83,619		69,175
Depreciation, Depletion and Amortization	157,800		132,764			306,862		251,950
Abandonment of Long-Lived Assets	115,479		—			115,479		—
Interest Expense	64,597		65,038			131,079		73,183
Taxes Other Than Income	88,642		79,124			179,331		160,425
Total Costs	1,489,144		1,193,199			2,703,444		2,291,091
Earnings Before Income Taxes	98,784		96,148			349,861		238,316
Income Taxes	21,400		25,248			80,328		59,534
Net Income	77,384		70,900			269,533		178,782
Less: Net Income Attributable to Noncontrolling Interest	—		(4,232		)	—		(11,845		)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	77,384	$	66,668		$	269,533	$	166,937
Earnings Per Share:
Basic	$	0.34	$	0.30		$	1.19	$	0.82
Dilutive	$	0.34	$	0.29		$	1.18	$	0.81
Weighted Average Number of Common Shares Outstanding:
Basic	226,647,752		225,715,539			226,499,994		203,842,526
Dilutive	229,138,024		228,081,103			228,917,335		206,311,383
Dividends Paid Per Share	$	0.10	$	0.10		$	0.20	$	0.20

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	(Unaudited)
	June 30, 2011		December 31, 2010
ASSETS
Current Assets:
Cash and Cash Equivalents	$	26,519	$	32,794
Accounts and Notes Receivable:
Trade	433,626		252,530
Other Receivables	23,318		21,589
Accounts Receivable—Securitized	70,000		200,000
Inventories	259,663		258,538
Deferred Income Taxes	174,612		174,171
Recoverable Income Taxes	44,920		32,528
Prepaid Expenses	118,192		142,856
Total Current Assets	1,150,850		1,115,006
Property, Plant and Equipment:
Property, Plant and Equipment	15,070,923		14,951,358
Less—Accumulated Depreciation, Depletion and Amortization	4,826,375		4,822,107
Total Property, Plant and Equipment—Net	10,244,548		10,129,251
Other Assets:
Deferred Income Taxes	461,581		484,846
Restricted Cash	20,291		20,291
Investment in Affiliates	100,951		93,509
Other	222,897		227,707
Total Other Assets	805,720		826,353
TOTAL ASSETS	$	12,201,118	$	12,070,610

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)



	(Unaudited)
	June 30, 2011			December 31, 2010
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	351,356		$	354,011
Short-Term Notes Payable	260,750			284,000
Current Portion of Long-Term Debt	25,283			24,783
Borrowings Under Securitization Facility	70,000			200,000
Other Accrued Liabilities	836,862			801,991
Total Current Liabilities	1,544,251			1,664,785
Long-Term Debt:
Long-Term Debt	3,126,061			3,128,736
Capital Lease Obligations	56,186			57,402
Total Long-Term Debt	3,182,247			3,186,138
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	3,085,834			3,077,390
Pneumoconiosis Benefits	175,523			173,616
Mine Closing	401,439			393,754
Gas Well Closing	116,096			130,978
Workers’ Compensation	149,025			148,314
Salary Retirement	136,366			161,173
Reclamation	46,661			53,839
Other	149,627			144,610
Total Deferred Credits and Other Liabilities	4,260,571			4,283,674
TOTAL LIABILITIES	8,987,069			9,134,597
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 226,695,195 Outstanding at June 30, 2011; 227,289,426 Issued and 226,162,133 Outstanding at December 31, 2010	2,273			2,273
Capital in Excess of Par Value	2,207,429			2,178,604
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	1,883,610			1,680,597
Accumulated Other Comprehensive Loss	(850,554		)	(874,338		)
Common Stock in Treasury, at Cost—594,231 Shares at June 30, 2011 and 1,127,293 Shares at December 31, 2010	(23,580		)	(42,659		)
Total CONSOL Energy Inc. Stockholders’ Equity	3,219,178			2,944,477
Noncontrolling Interest	(5,129		)	(8,464		)
TOTAL EQUITY	3,214,049			2,936,013
TOTAL LIABILITIES AND EQUITY	$	12,201,118		$	12,070,610

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)



	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2010	$	2,273	$	2,178,604	$	1,680,597		$	(874,338	)	$	(42,659	)	$	2,944,477		$	(8,464	)	$	2,936,013
(Unaudited)
Net Income	—		—		269,533			—			—			269,533			—			269,533
Treasury Rate Lock (Net of $59 Tax)	—		—		—			(96		)	—			(96		)	—			(96		)
Gas Cash Flow Hedge (Net of $2,332 Tax)	—		—		—			(2,944		)	—			(2,944		)	—			(2,944		)
Actuarially Determined Long-Term Liability Adjustments (Net of $16,693 Tax)	—		—		—			26,824			—			26,824			—			26,824
Comprehensive Income (Loss)	—		—		269,533			23,784			—			293,317			—			293,317
Issuance of Treasury Stock	—		—		(21,227		)	—			19,079			(2,148		)	—			(2,148		)
Tax Benefit From Stock-Based Compensation	—		3,250		—			—			—			3,250			—			3,250
Amortization of Stock-Based Compensation Awards	—		25,575		—			—			—			25,575			—			25,575
Net Change in Crown Drilling Noncontrolling Interest	—		—		—			—			—			—			3,335			3,335
Dividends ($0.20 per share)	—		—		(45,293		)	—			—			(45,293		)	—			(45,293		)
Balance at June 30, 2011	$	2,273	$	2,207,429	$	1,883,610		$	(850,554	)	$	(23,580	)	$	3,219,178		$	(5,129	)	$	3,214,049

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Six Months Ended
	June 30,
	2011			2010
Operating Activities:
Net Income	$	269,533		$	178,782
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	306,862			251,950
Abandonment of Long-Lived Assets	115,479			—
Stock-Based Compensation	25,575			20,049
Gain on Sale of Assets	(5,139		)	(866		)
Loss on Debt Extinguishment	16,090			—
Amortization of Mineral Leases	3,578			3,981
Deferred Income Taxes	7,592			7,740
Equity in Earnings of Affiliates	(11,312		)	(8,692		)
Changes in Operating Assets:
Accounts and Notes Receivable	(51,097		)	(76,977		)
Inventories	(1,708		)	13,607
Prepaid Expenses	23,679			4,712
Changes in Other Assets	15,307			19,475
Changes in Operating Liabilities:
Accounts Payable	21,184			25,409
Other Operating Liabilities	23,391			64,643
Changes in Other Liabilities	29,607			(18,008		)
Other	6,862			20,037
Net Cash Provided by Operating Activities	795,483			505,842
Investing Activities:
Capital Expenditures	(585,441		)	(577,625		)
Acquisition of Dominion Exploration and Production Business	—			(3,475,665		)
Purchase of CNX Gas Noncontrolling Interest	—			(991,034		)
Proceeds from Sales of Assets	7,480			2,487
Net Investment in Equity Affiliates	3,870			5,101
Net Cash Used in Investing Activities	(574,091		)	(5,036,736		)
Financing Activities:
Payments on Short-Term Borrowings	(23,250		)	(114,300		)
Payments on Miscellaneous Borrowings	(7,105		)	(5,590		)
(Payments on) Proceeds from Securitization Facility	(130,000		)	150,000
Payments on Long-Term Notes, Including Redemption Premium	(265,785		)	—
Proceeds from Issuance of Long-Term Notes	250,000			2,750,000
Tax Benefit from Stock-Based Compensation	4,181			9,714
Dividends Paid	(45,293		)	(40,694		)
Proceeds from Issuance of Common Stock	—			1,828,862
Issuance of Treasury Stock	5,012			2,175
Debt Issuance and Financing Fees	(15,427		)	(80,567		)
Net Cash (Used In) Provided By Financing Activities	(227,667		)	4,499,600
Net Decrease in Cash and Cash Equivalents	(6,275		)	(31,294		)
Cash and Cash Equivalents at Beginning of Period	32,794			65,607
Cash and Cash Equivalents at End of Period	$	26,519		$	34,313

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2010 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, 2010 included in CONSOL Energy Inc.'s Form 10-K.

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 assumed exercise of stock options and performance stock options and the assumed vesting of restricted and performance stock units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. CONSOL Energy Inc. (CONSOL Energy or Company) includes the impact of pro forma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2011	2010	2011	2010
Anti-Dilutive Options	987,471	822,749	1,005,303	822,749
Anti-Dilutive Restricted Stock Units	2,099	1,960	—	1,960
	989,570	824,709	1,005,303	824,709

The table below sets forth the share based awards that have been exercised or released:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2011	2010	2011	2010
Options	58,353	62,813	238,749	122,793
Restricted Stock Units	63,228	31,576	404,369	305,344
Performance Share Units	—	—	40,752	109,955
	121,581	94,389	683,870	538,092

The weighted average exercise price per share of the options exercised during the three months ended June 30, 2011 and 2010 was $ 22.50 and $ 15.56 , respectively. The weighted average exercise price per share of the options exercised during the six months ended June 30, 2011 and 2010 was $21.00 and $ 18.02 , respectively.

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



	Three Month Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Net income attributable to CONSOL Energy Inc. shareholders	$	77,384	$	66,668	$	269,533	$	166,937
Weighted average shares of common stock outstanding:
Basic	226,647,752		225,715,539		226,499,994		203,842,526
Effect of stock-based compensation awards	2,490,272		2,365,564		2,417,341		2,468,857
Dilutive	229,138,024		228,081,103		228,917,335		206,311,383
Earnings per share:
Basic	$	0.34	$	0.30	$	1.19	$	0.82
Dilutive	$	0.34	$	0.29	$	1.18	$	0.81

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

On April 30, 2010 , CONSOL Energy completed the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition) for a cash payment as of June 30, 2010 of $3,475,665 . The final purchase price of $3,470,212 was principally allocated to oil and gas properties, wells and well-related equipment. The acquisition, which was accounted for under the acquisition method of accounting, includes approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million net acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings are approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition enhanced CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.

The unaudited pro forma results for the three and six months ended June 30, 2010 , assuming the acquisition had occurred at January 1, 2010, are presented below. Pro forma adjustments include estimated operating results, acquisition and financing fees incurred, additional interest related to the $2.75 billion of senior unsecured notes and 44,275,000 shares of common stock issued in connection with the transaction.



	Three Months		Six Months
	Ended		Ended
	June 30,		June 30,
	2010		2010
Total Revenue and Other Income	$	1,302,850	$	2,596,394
Earnings Before Income Taxes	$	105,912	$	184,608
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	72,502	$	134,916
Basic Earnings Per Share	$	0.32	$	0.60
Dilutive Earnings Per Share	$	0.32	$	0.59

The pro forma results are not necessarily indicative of what actually would have occurred if the Dominion Acquisition had been completed as of January 1, 2010, nor are they necessarily indicative of future consolidated results.

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 of CONSOL Energy (CNX Gas Acquisition). All of the shares of CNX Gas that were not already owned by CONSOL Energy were acquired at a price of $38.25 per share. 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 but unexercised 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.

CONSOL Energy incurred $17,515 and $64,078 of acquisition-related costs as a direct result of the Dominion and CNX Gas Acquisitions for the three and six months ended June 30, 2010 , respectively. These expenses have been included within Acquisition and Financing Fees on the Consolidated Statements of Income for the period ended June 30, 2010 .

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 recoupable against future production. Both payments were made per a settlement agreement in regards to the depositing of untreated water from Buchanan Mine, a mine operated by one of our subsidiaries, into the void spaces of the nearby mines of one of our other subsidiaries, Island Creek Coal Company.

In March 2010, CONSOL Energy completed the sale of the 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 overriding royalty on future mineable and merchantable coal extracted and sold from the property.

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

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



	Pension Benefits												Other Postretirement Benefits
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	4,440		$	3,736		$	8,729		$	7,213		$	2,862		$	2,808		$	6,839		$	6,540
Interest cost	9,794			9,369			18,872			18,597			47,665			40,874			89,869			81,366
Expected return on plan assets	(9,631		)	(9,206		)	(19,261		)	(18,524		)	—			—			—			—
Amortization of prior service cost (credits)	(166		)	(183		)	(333		)	(367		)	(11,600		)	(11,604		)	(23,199		)	(23,207		)
Recognized net actuarial loss	9,905			8,070			19,051			15,935			30,318			17,674			52,682			35,072
Net periodic benefit cost	$	14,342		$	11,786		$	27,058		$	22,854		$	69,245		$	49,752		$	126,191		$	99,771

For the six months ended June 30, 2011 , $ 31,868 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 $ 71,700 to the pension trust in 2011 .

CONSOL Energy does not expect to contribute to the other postemployment benefit plan in 2011 . We intend to pay benefit claims as they become due. For the six months ended June 30, 2011 , $84,862 of other postemployment benefits have been paid.

For the six months ended June 30, 2011, $7,781 of proceeds were received under the Patient Protection and Affordable Care Act related to reimbursements from the Federal government for retiree health spending. The proceeds were recorded in Accumulated Other Comprehensive Income in the Consolidated Balance Sheets. There is no guarantee that additional proceeds will be received under this program.

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 six months ended June 30 are as follows:



	CWP												Workers’ Compensation
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	1,155		$	1,040		$	2,310		$	2,986		$	4,468		$	6,754		$	8,936		$	13,508
Interest cost	2,332			2,681			4,665			5,427			2,059			2,289			4,119			4,578
Amortization of actuarial gain	(5,477		)	(5,777		)	(10,955		)	(10,758		)	(976		)	(768		)	(1,953		)	(1,536		)
State administrative fees and insurance bond premiums	—			—			—			—			1,986			1,799			3,208			4,218
Legal and administrative costs	750			750			1,500			1,500			719			785			1,437			1,570
Net periodic (benefit) cost	$	(1,240	)	$	(1,306	)	$	(2,480	)	$	(845	)	$	8,256		$	10,859		$	15,747		$	22,338

CONSOL Energy does not expect to contribute to the CWP plan in 2011. We intend to pay benefit claims as they become due. For the six months ended June 30, 2011 , $ 6,346 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2011. We intend to pay benefit claims as they become due. For the six months ended June 30, 2011 , $ 16,002 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

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



	For the Six Months Ended June 30,
	2011					2010
	Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	122,451		35.0	%	$	83,411		35.0	%
Excess tax depletion	(52,839		)	(15.1	)	(30,186		)	(12.7	)
Effect of domestic production activities	(5,131		)	(1.5	)	(3,293		)	(1.4	)
Net effect of state income taxes	11,906			3.4		8,009			3.4
Other	3,941			1.2		1,593			0.7
Income Tax Expense / Effective Rate	$	80,328		23.0	%	$	59,534		25.0	%

The effective rate for the six months ended June 30, 2011 was calculated using the annual effective rate projection on recurring earnings. The effective rate for the six months ended June 30, 2010 was calculated using the annual effective rate projection on recurring earnings and includes tax liabilities related to certain discrete transactions which are 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 $3,450 as a discrete reduction to foreign income tax expense in the six months ended June 30, 2010. As a result of the foreign income tax reduction, the Company reflected an additional $1,457 as discrete federal income tax expense. This discrete transaction was reflected in the Other line of the rate reconciliation in 2010.

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 in the six months ended June 30, 2010. Accordingly, a discrete reduction to federal income tax expense of $ 624 was also recognized related to this transaction. This discrete transaction was reflected in the Net effect of state income taxes line of the rate reconciliation in 2010.

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 the CONSOL Energy is entitled to a credit for unused NOLs against future CAT liabilities. These NOLs were previously fully reserved. In the six months ended June 30, 2010, 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. This discrete transaction was reflected in the Net effect of state income taxes line of the rate reconciliation in 2010.

The total amounts of uncertain tax positions at June 30, 2011 and 2010 were $ 65,510 and $ 56,916 , respectively. If these uncertain tax positions were recognized, approximately $ 16,802 and $ 15,502 , respectively, would affect CONSOL Energy’s effective tax rate. There were no new uncertain tax positions taken during the six months ended June 30, 2011 and 2010 .

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

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of June 30, 2011 and 2010 , the Company reported an accrued interest liability relating to uncertain tax positions of $ 13,043 and $ 9,831 , respectively. The accrued interest liability includes $ 2,269 and $ 1,493 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the six months ended June 30, 2011 and 2010 , respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of June 30, 2011 and 2010 , CONSOL Energy had no accrued liability for tax penalties.

NOTE 6—INVENTORIES:

Inventory components consist of the following:



	June 30, 2011		December 31, 2010
Coal	$	105,860	$	108,694
Merchandise for resale	50,299		50,120
Supplies	103,504		99,724
Total Inventories	$	259,663	$	258,538

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 $ 24,608 and $ 19,624 at June 30, 2011 and December 31, 2010 , respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $200,000 . The facility also allows for the issuance of letters of credit against the $200,000 capacity. At June 30, 2011 , there were no letters of credit outstanding against the facility.

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

program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

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 $ 572 and $ 1,297 for three and six months ended June 30, 2011 , respectively. Costs associated with the receivables facility totaled $ 552 and $ 1,005 for three and six months ended June 30, 2010, 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 .

At June 30, 2011 and December 31, 2010 , eligible accounts receivable totaled $ 200,000 . There was subordinated retained interest of $130,000 at June 30, 2011 and there was no subordinated retained interest at December 31, 2010 . At June 30, 2011 and December 31, 2010 , $ 70,000 and $ 200,000 , respectively, were recorded as Accounts Receivable – Securitization and Borrowings under the Securitization Facility on the Consolidated Balance Sheet. For the six months ended June 30, 2011 and 2010, the respective $130,000 decrease and $ 150,000 increase in the accounts receivable securitization program were reflected in Net Cash (Used in) Provided by Financing Activities in the Consolidated Statement of Cash Flows. 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:



	June 30, 2011		December 31, 2010
Coal & other plant and equipment	$	5,059,020	$	5,100,085
Unproven gas properties	2,214,010		2,206,399
Proven gas properties	1,671,584		1,662,605
Coal properties and surface lands	1,303,991		1,292,701
Intangible drilling cost	1,285,908		1,116,884
Gas gathering equipment	1,025,893		941,772
Airshafts	673,830		662,315
Leased coal lands	539,943		536,603
Mine development	424,918		587,518
Coal advance mining royalties	393,970		389,379
Gas wells and related equipment	391,290		367,448
Other gas assets	83,216		84,571
Gas advance royalties	3,350		3,078
Total property, plant and equipment	15,070,923		14,951,358
Less Accumulated depreciation, depletion and amortization	4,826,375		4,822,107
Total Net Property, Plant and Equipment	$	10,244,548	$	10,129,251

Long-Lived Asset Abandonment

In June 2011, CONSOL Energy decided to permanently close its Mine 84 mining operation located near Washington, PA. This decision is part of CONSOL Energy's ongoing effort to reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The closure decision resulted in the recognition of an abandonment expense of $ 115,479 for the three and six months ended June 30, 2011. The abandonment expense resulted from the removal of the June 30, 2011 carrying value of the following Mine 84 related assets from the Consolidated Balance Sheets: Mine development - $ 92,136 , Airshafts - $ 15,352 , Coal equipment - $ 2,080 , Inventories - $ 419 , and Prepaid Expenses - $ 385 . Additionally, the Mine 84 abandonment expense also includes the recognition of a Mine Closing expense of $ 5,107 . The effect on net income of the Mine 84 abandonment expense was $75,061 for the three and six months ended June 30, 2011, or $0.33 per share, both basic and diluted, for both periods.

NOTE 9—SHORT-TERM NOTES PAYABLE:

On April 12, 2011, CONSOL Energy amended and extended its $ 1,500,000 Senior Secured Credit Agreement through April 12, 2016. The previous facility was set to expire on May 7, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1,500,000 of borrowings and letters of credit. CONSOL Energy can request an additional $ 250,000 increase in the aggregate borrowing limit amount. 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 2.50 to 1.00, measured quarterly. The interest coverage ratio was 4.90 to 1.00 at June 30, 2011 . The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The leverage ratio was 2.42 to 1.00 at June 30, 2011 . The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio was 0.21 to 1.00 at June 30, 2011 . 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 notes. At June 30, 2011 , the $1,500,000 facility had no borrowings outstanding and $ 266,778 of letters of credit outstanding, leaving $ 1,233,222 of capacity available for borrowings and the issuance of letters of credit. The average interest rate for the three months and six months ended June 30, 2011 was 4.54% and 4.09% , respectively. Accrued interest of $ 148 and $ 249 is included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 , respectively.

On April 12, 2011, CNX Gas entered into a $ 1,000,000 Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the $ 700,000 Senior Secured Credit Facility which was set to expire on May 6, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 for borrowings and letters of credit. CNX Gas can request an additional $ 250,000 increase in the aggregate borrowing limit amount. The facility was established to meet the asset development needs of the company. 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 1.15 to 1.00 at June 30, 2011 . The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 44.69 to 1.00 at June 30, 2011 . At June 30, 2011 , the $ 1,000,000 facility had $ 260,750 of borrowings outstanding and $ 70,203 of letters of credit outstanding, leaving $ 669,047 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.76% at June 30, 2011 . The average interest rate for the three months and six months ended June 30, 2011 was 1.98% and 2.19% , respectively. Accrued interest of $ 228 and $ 98 is included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 , respectively.

NOTE 10—LONG-TERM DEBT:



	June 30, 2011		December 31, 2010
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		—
Senior secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $242 at December 31, 2010)	—		249,758
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.56% weighted average interest rate for June 30, 2011 and December 31, 2010)	32,211		32,211
Note Due December 2012 at 4.28%	7,648		10,438
Other long-term notes maturing at various dates through 2031	80		93
	3,142,804		3,145,365
Less amounts due in one year	16,743		16,629
Long-Term Debt	$	3,126,061	$	3,128,736

On March 9, 2011 CONSOL Energy closed the offering of $250,000 of 6.375% senior notes which mature on March 1, 2021 . The notes are guaranteed by substantially all of our existing wholly owned domestic subsidiaries.

On April 11, 2011 , CONSOL Energy redeemed all of its outstanding $ 250,000 , 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $ 250,000 , a make-whole premium of $ 15,785 and accrued interest of $ 2,188 for a total redemption cost of $ 267,973 . The loss on extinguishment of debt was $ 16,090 , which primarily represents the interest that would have been paid on these notes if held to maturity.

Accrued interest related to Long-Term Debt of $ 62,870 and $ 64,009 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 , 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, individually and in the aggregate, may be material to the financial position, results of operations or cash flows of CONSOL Energy.

Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the 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 at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently altered the 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 the DEP reviewed the issue of whether the dam was damaged by subsidence. On February 16, 2010, the DEP issued its interim report, concluding that the alleged damage was subsidence related. In the next phase of the DEP proceeding, which was the damage phase, the DEP determined that the Company must repair the dam. The DEP estimated the cost of repair to be approximately $ 20,000 . The Company has appealed the DEP's findings 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. In order to perfect its appeal to the PEHB under the applicable statute, the Company deposited $ 20,291 into escrow as security for the DEP's estimated cost of repair. This amount is reflected as restricted cash on the Consolidated Balance Sheets at June 30, 2011 and December 31, 2010.

The Company is seeking to substitute an appeal bond for the cash deposit. 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. On March 31, 2011, the DEP informed the parties that it was withdrawing its Order requiring the Company to repair the dam because of additional movements of the dam site, well after mining had ceased; therefore, that movement would preclude repair of the dam as a remedy. On May 18, 2011, the DEP attempted to reinstate its order requiring repair of the dam. The Company filed a motion to vacate that order, arguing that the DEP cannot reinstate an order which was withdrawn in the manner in which the DEP attempted to do so. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims.

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 7,500 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Texas and Illinois. This number has been reduced from the 22,500 pending claims that were previously reported after a review of the dockets where these cases are pending found that approximately 15,000 cases had been dismissed by administrative order, without the payment of any damages or settlement amounts. 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.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy's interim allocation share from 46% to 32% . In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties. The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA's past and future cost, is approximately $ 65,000 . 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 sixty other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was no expense recognized in the three and six months ended June 30, 2011 related to this matter. There was $ 2,880 of expense recognized in cost of goods sold and other charges in the three and six months ended June 30, 2010 related to this matter. CONSOL Energy funded $ 250 in the six months ended June 30, 2011 to an independent trust established for this remediation. CONSOL Energy funded $ 1,209 in the six months ended June 30, 2010 to the trust. As of June 30, 2011, 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 recoveries from settled claims is $ 4,372 . Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at June 30, 2011 is $ 3,588 .

C. L. Ritter: On March 1, 2011, the Company was served with a complaint instituted by C. L. Ritter Lumber Company Incorporated against Consolidation Coal Company (CCC), Island Creek Coal Company, (ICCC), CNX Gas Company LLC, subsidiaries of CONSOL Energy Inc., as well as CONSOL Energy itself in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC's Buchanan Mine into nearby void spaces at one of the mines of ICCC. The suit alleges damages of up to $ 300,000 for alleged damage to coal and coalbed methane, as well as breach of contract damages. We have removed the case to federal court and filed a motion to dismiss. Three similar lawsuits were filed recently in the same court by other plaintiffs; the Company intends to file motions to dismiss those suits as well. CCC believes that it had, and continues to have, the right to store water in these void areas. CCC and the other named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine. Consequently, we have not recognized any liability related to these actions.

South Carolina Gas & Electric Company Arbitration: South Carolina Electric & Gas Company (SCE&G), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 2011. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them.

Northern Appalachia Water Issues: In the Fall of 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill and continuing thereafter, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection (WVDEP) that set forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the WVDEP issued a Unilateral Order that imposed additional conditions on CCC's discharges into Dunkard Creek and required CCC to develop a plan for long-term treatment of those and other high-chloride discharges. Pursuant to the Unilateral Order as well as a subsequent Unilateral Order issued by the WVDEP, 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 and related facilities may reach or exceed $200,000 . CCC negotiated a joint Consent Decree with the U.S. Environmental Protection Agency (EPA) and the WVDEP that includes a compliance plan and schedule. The Consent Decree, which has been finalized, included a civil penalty of $5,500 , which was previously accrued, to settle alleged past violations related to chlorides, without any admission of liability. CCC also negotiated a settlement with the WVDEP and the West Virginia Department of Natural Resources settling state claims for natural resource damages for $500 , without any admission of liability.

CNX Gas Shareholders Litigation: 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 for $38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the three cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL). With one exception, these cases 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 breached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 per share price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, the actions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys' fees and expenses. The Delaware Court of Chancery denied an injunction against the tender offer and CONSOL Energy completed the acquisition of the outstanding shares of CNX Gas on June 1, 2010. The Delaware Court of Chancery certified to the Delaware Supreme Court the question of what legal standard should be applied to the tender offer, which would effectively 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 to trial, possibly later in 2011. There may be mediation prior to any trial. CONSOL Energy believes that these actions are without merit and intends to defend them vigorously.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, Virginia 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 force pooling of CBM, that the Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the force 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 (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty, and that CNX Gas need not distribute the net proceeds to class members. The Magistrate Judge recommended against the dismissal of certain other claims, none of which are believed to have any significance. We have appealed that recommendation to the trial judge and are awaiting a decision. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in Federal court in Virginia styled Addison v. CNX Gas Company LLC. The case involves two primary claims: (i) the plaintiff and similarly situated CNX Gas lessors identified as conflicting claimants during the force pooling process before the Virginia Gas and Oil Board are the owners of the CBM and, accordingly, the owners of the escrowed royalty payments being held by the Commonwealth of Virginia; and (ii) CNX Gas failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiffs seek a declaratory judgment regarding ownership and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking), for force pooling coal owners after the Ratliff decision declared coal owners did not own the CBM; negligent breach of duties as an operator; breach of fiduciary duties; and unjust enrichment. We filed a Motion to Dismiss in this case, which is pending. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court. The named plaintiff is Earl D. Hall. The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy. The complaint alleges more than 1,000 similarly situated lessors. The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying royalties on oil production. The complaint also alleges that royalty statements were false and misleading. The complaint seeks damages, interest and an accounting on a well-by-well basis. The plaintiff amended the complaint and we have filed preliminary objections. In response to our preliminary objections, the Court dismissed the plaintiffs' claims for underpayment of royalties on gas lost or used before the point of sale and allowed the plaintiffs to amend their complaint to specifically state their claim on oil production. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 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 removing CNX Gas from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summary judgment motion on that issue. The court will hold a bench trial on the “roof/rider” coal issue in 2011. CNX Gas and CONSOL Energy believe this lawsuit to be without merit and intends to vigorously defend it.

Severance Tax Litigation: In December 2010, Tazewell County, Virginia asserted a claim for the tax year 2007, although the County has not filed a lawsuit against CNX Gas Company LLC. The complaint alleged 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. We continued to pay Tazewell County taxes based on our method of calculating the taxes. CONSOL Energy is evaluating the merits of that claim.

Decker/Gillingham Litigation: Two contractor employees-Messrs. Decker and Gillingham-were injured when a stairway affixed to the exterior of a building collapsed at CONSOL Energy's Research and Development facility in Allegheny County, Pennsylvania in 2007. Mr. Decker sustained a broken hip and leg. Mr. Gillingham sustained a torn rotator cuff. Both men have recovered and are working, although both claim that the accident has limited their ability to perform their jobs. Messrs. Decker and Gillingham sued CONSOL Energy on June 4, 2008 and June 20, 2008, respectively, in Allegheny County Common Pleas Court, alleging, among other things, that CONSOL Energy was negligent in the maintenance of the stairway. The cases were consolidated. In late November, 2010, after a jury trial, the jury found that CONSOL Energy was negligent in maintaining the stairway and the jury awarded Mr. Decker and his spouse $ 5,000 and Mr. Gillingham and his spouse $ 2,800 . These amounts included compensatory damages, as well as damages for pain and suffering, embarrassment and humiliation, and loss of ability to enjoy the pleasures of life. We intend to appeal the verdict. We have accrued $ 5,000 which was included in Other Accrued Liabilities for this claim. CONSOL Energy maintains insurance for damages and costs in excess of $ 5,000 .

Royalty Owners Group Litigation: These five separate but related cases, filed on February 13, 2006 in the Circuit Court of Buchanan County, Virginia, involve claims by several of CNX Gas's lessors in southwest Virginia that certain improper deductions have been made on their royalty payments by CNX Gas with respect to the period from 1999 to the present. The deductions at issue primarily relate to post production expenses of gathering, compression and transportation. Specifically, the plaintiffs allege that (i) CNX Gas' gathering system in its Virginia field is over built, (ii) CNX Gas is not entitled to deductions for certain compression costs, because that is a production activity, not a post-production activity, and (iii) CNX Gas is not

entitled to a deduction for firm transportation expense, because that is a marketing activity, not a post-production cost. The litigation has settled, with the Company paying the lessors $ 1,000 , which was previously accrued, and the Company will take a fixed deduction from royalties going forward.

Comer: In 2005, plaintiffs Ned Comer and others filed a purported class action lawsuit in the U.S. District Court for the Southern District of Mississippi against a number of companies in energy, fossil fuels and chemical industries, including CONSOL Energy styled, Comer, et al. v. Murphy Oil, et al. The plaintiffs, residents and owners of property along the Mississippi Gulf coast, alleged that the defendants caused the emission of greenhouse gasses that contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to destroy the plaintiffs' property. The District Court dismissed the case and the plaintiffs appealed. The Circuit Court panel reversed and the defendants sought a rehearing before the entire court. A rehearing before the entire court was granted, which had the effect of vacating the panel's reversal, but before the case could be heard on the merits, a number of judges recused themselves and there was no longer a quorum. As a result, the District Court's dismissal was effectively reinstated. The plaintiffs asked the U.S. Supreme Court to require the Circuit Court to address the merits of their appeal. On January 11, 2011, the Supreme Court denied that request. Although that should have resulted in the dismissal being a finality, the plaintiffs filed a lawsuit on May 27, 2011, in the same jurisdiction against essentially the same defendants making nearly identical allegations as in the original lawsuit. The defendants intend to seek an early dismissal of the case.

Rasnake Litigation: On August 28, 2006, plaintiffs filed a complaint in Russell County Circuit Court of Lebanon, Virginia, involving the CBM located on four separate tracts of land located in Russell and Buchanan Counties, Virginia (the “Subject Property”). Plaintiffs allege that CNX Gas is trespassing upon the Subject Property by producing CBM therefrom without authorization. Plaintiffs also allege that CNX Gas has committed slander on plaintiffs' title by failing to properly recognize their ownership interest in the Subject Property when submitting pooling applications to the Virginia Gas and Oil Board. The plaintiffs seek trespass damages in an amount equal to the total revenue from the wells. We believe that their trespass claim is without merit because we produced the gas pursuant to a force pooling order from the Virginia Gas and Oil Board and we believe total revenue is not the proper remedy for trespass damages. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas, Dominion Resources, and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but they farmed out the development of the lease to Dominion, in exchange for an overriding royalty. Dominion sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas as part of an internal reorganization. Rowland alleges that (i) Dominion's sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and (ii) the subsequent merger of the subsidiary into CNX Gas was an assignment that required its consent under the lease. Rowland alleges that the failure to obtain the required consent constitutes a breach of the lease and it seeks damages and a forfeiture of the lease. CONSOL Energy and CNX Gas have filed a motion to dismiss the complaint, arguing among other things, that Dominion's sale of the indirect subsidiary was not a change in control; that even if the sale constituted a change in control, the purchase agreement between Dominion and CONSOL Energy did not give effect to the transfer so the transfer never occurred; that the mergers did not require consent; and that Rowland did not provide timely notice of breach of the lease in accordance with its terms. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Majorsville Storage Field Declaratory Judgment: On March 3, 2011, an attorney sent a letter to CNX Gas regarding certain leases that CNX Gas obtained from Columbia Gas in Greene County, Pennsylvania involving the Majorsville Storage Field. The letter was written on behalf of three lessors alleging that the leases totaling 525 acres are invalid, and had expired by their terms. The plaintiffs' theory is that the rights of storage and production are severable under the leases. Ignoring the fact that the leases have been used for gas storage, they claim that since there has been no production or development of production, the right to produce gas expired at the end of the primary terms. On June 16, 2011 in the Court of Common Pleas of Greene County, Pennsylvania, the Company filed a declaratory judgment action, seeking to have a court confirm the validity of the leases. We believe that we will prevail in this litigation based on the language of the leases and the current status of the law.

At June 30, 2011 , 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 credit 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	$	199,553	$	97,110	$	102,443	$	—	$	—
Environmental	56,994		55,266		1,728		—		—
Gas	70,203		55,270		14,933		—		—
Other	10,305		10,141		164		—		—
Total Letters of Credit	337,055		217,787		119,268		—		—
Surety Bonds:
Employee-Related	205,645		194,145		11,500		—		—
Environmental	434,652		426,171		8,481		—		—
Gas	6,542		6,541		—		—		1
Other	17,039		17,039		—		—		—
Total Surety Bonds	663,878		643,896		19,981		—		1
Guarantees:
Coal	91,678		70,158		16,020		1,000		4,500
Gas	95,198		42,067		22,509		—		30,622
Other	372,531		70,765		119,976		71,817		109,973
Total Guarantees	559,407		182,990		158,505		72,817		145,095
Total Commitments	$	1,560,340	$	1,044,673	$	297,754	$	72,817	$	145,096

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.

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 June 30, 2011 , the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	216,374
1 - 3 years	226,744
3 - 5 years	72,423
More than 5 years	294,978
Total Purchase Obligations	$	810,519

Costs related to these purchase obligations include:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Major equipment purchases	$	9,522	$	8,946	$	17,177	$	27,151
Firm transportation expense	15,316		9,408		28,134		16,103
Gas drilling obligations	26,244		832		52,062		1,437
Other	89		150		190		180
Total costs related to purchase obligations	$	51,171	$	19,336	$	97,563	$	44,871

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 June 30, 2011 , the total notional amount of the Company’s outstanding natural gas swap contracts was 158.1 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2014 and meet the criteria for cash flow hedge accounting. During the next twelve months, $ 29,762 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings, as a result of the settlement of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The fair value at June 30, 2011 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify for hedging, were an asset of $ 76,734 and a liability of $ 5,807 . The total asset is comprised of $ 51,374 and $ 25,360 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $ 2,447 and $ 3,360 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The effect of derivative instruments on the Consolidated Statements of Income for the three months ended June 30, 2011 is as follows:



Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2011		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2011		Location of Gain Recognized in Income on Derivative	Amount of Gain Recognized in Income on Derivative 2011
Natural Gas Price Swaps	$	28,503	Outside Sales	$	16,905	Outside Sales	$	72
Total	$	28,503		$	16,905		$	72

The effect of derivative instruments on the Consolidated Statements of Income for the six months ended June 30, 2011 is as follows:



Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2011		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2011		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income on Derivative 2011
Natural Gas Price Swaps	$	32,765	Outside Sales	$	35,745	Outside Sales	$	(36	)
Total	$	32,765		$	35,745		$	(36	)

The fair value at December 31, 2010 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify for hedging, were an asset of $ 79,960 and a liability of $ 3,720 . The total asset is comprised of $ 52,022 and $ 27,938 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $ 3,191 and $ 529 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The effect of derivative instruments on the Consolidated Statements of Income for the three months ended June 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	$	14,820	Outside Sales	$	54,535	Outside Sales	$	290
Total	$	14,820		$	54,535		$	290

The effect of derivative instruments on the Consolidated Statements of Income for the six months ended June 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 Gain Recognized in Income on Derivative 2010
Natural Gas Price Swaps	$	89,528	Outside Sales	$	97,934	Outside Sales	$	148
Total	$	89,528		$	97,934		$	148

NOTE 13—OTHER COMPREHENSIVE LOSS:

Total comprehensive income (loss), net of tax, for the six months ended June 30, 2011 is as follows:



	Treasury Rate Lock			Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Accumulated Other Comprehensive Loss
Balance at December 31, 2010	$	96		$	46,087		$	(920,521	)	$	(874,338	)
Net increase in value of cash flow hedges	—			32,765			—			32,765
Reclassification of cash flow hedges from other comprehensive income to earnings	—			(35,709		)	—			(35,709		)
Current period change	(96		)	—			26,824			26,728
Balance at June 30, 2011	$	—		$	43,143		$	(893,697	)	$	(850,554	)

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 June 30, 2011						Fair Value Measurements at December 31, 2010
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		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	$	—	$	70,927	$	—	$	—	$	76,240	$	—

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.

Restricted cash: The carrying amount reported in the balance sheets for restricted cash 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:



	June 30, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	26,519		$	26,519		$	32,794		$	32,794
Restricted cash	$	20,291		$	20,291		$	20,291		$	20,291
Short-term notes payable	$	(260,750	)	$	(260,750	)	$	(284,000	)	$	(284,000	)
Borrowings under Securitization Facility	$	(70,000	)	$	(70,000	)	$	(200,000	)	$	(200,000	)
Long-term debt	$	(3,142,804	)	$	(3,361,209	)	$	(3,145,365	)	$	(3,341,406	)

NOTE 15—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal division are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Steam, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three and six months ended June 30, 2011 , the Steam aggregated segment includes the following mines: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the three and six months ended June 30, 2011 , the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the three and six months ended June 30, 2011 , the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, Miller Creek Complex and Robinson Run 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 division is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas division 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 division 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. 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.

Industry segment results for three months ended June 30, 2011 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	$	781,395	$	279,171	$	117,688	$	33,493		$	1,211,747	$	115,985	$	27,640	$	42,180		$	3,236		$	189,041	$	85,212	$	—		$	1,486,000
Sales—purchased gas	—		—		—		—			—		—		—		—			1,162			1,162		—		—			1,162
Sales—gas royalty interests	—		—		—		—			—		—		—		—			16,273			16,273		—		—			16,273
Freight—outside	—		—		—		59,572			59,572		—		—		—			—			—		—		—			59,572
Intersegment transfers	—		—		—		—			—		—		—		—			929			929		55,243		(56,172		)	—
Total Sales and Freight	$	781,395	$	279,171	$	117,688	$	93,065		$	1,271,319	$	115,985	$	27,640	$	42,180		$	21,600		$	207,405	$	140,455	$	(56,172	)	$	1,563,007
Earnings (Loss) Before Income Taxes	$	109,815	$	184,374	$	46,973	$	(189,012	)	$	152,150	$	39,413	$	6,497	$	(511	)	$	(17,153	)	$	28,246	$	4,422	$	(86,034	)	$	98,784	(A)
Segment assets										$	5,026,836											$	6,096,958	$	317,677	$	759,647		$	12,201,118	(B)
Depreciation, depletion and amortization										$	101,915											$	51,314	$	4,571	$	—		$	157,800
Capital expenditures										$	152,700											$	168,599	$	9,364	$	—		$	330,663


(A)	Includes equity in earnings of unconsolidated affiliates of $ 4,240 , $ 517 and $ 1,074 for Coal, Gas and All Other, respectively.


(B)	Includes investments in unconsolidated equity affiliates of $ 26,995 , $ 24,570 and $ 49,386 for Coal, Gas and All Other, respectively.

Industry segment results for three months ended June 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	$	745,596	$	149,145	$	55,655	$	6,098		$	956,494	$	149,304	$	10,399	$	30,067	$	1,659		$	191,429	$	72,193	$	—		$	1,220,116
Sales—purchased gas	—		—		—		—			—		—		—		—		1,740			1,740		—		—			1,740
Sales—gas royalty interests	—		—		—		—			—		—		—		—		14,151			14,151		—		—			14,151
Freight—outside	—		—		—		28,075			28,075		—		—		—		—			—		—		—			28,075
Intersegment transfers	—		—		—		—			—		—		—		—		696			696		43,566		(44,262		)	—
Total Sales and Freight	$	745,596	$	149,145	$	55,655	$	34,173		$	984,569	$	149,304	$	10,399	$	30,067	$	18,246		$	208,016	$	115,759	$	(44,262	)	$	1,264,082
Earnings (Loss) Before Income Taxes	$	103,636	$	84,790	$	27,792	$	(98,724	)	$	117,494	$	70,922	$	274	$	3,078	$	(20,080	)	$	54,194	$	6,255	$	(81,795	)	$	96,148	(C)
Segment assets										$	4,946,425										$	5,818,535	$	311,613	$	611,518		$	11,688,091	(D)
Depreciation, depletion and amortization										$	79,424										$	48,953	$	4,387	$	—		$	132,764
Capital expenditures										$	185,343										$	3,599,146	$	3,457	$	—		$	3,787,946


(C)	Includes equity in earnings of unconsolidated affiliates of $ 3,998 , ($208) and $ 1,029 for Coal, Gas and All Other, respectively.


(D)	Includes investments in unconsolidated equity affiliates of $ 17,296 , $ 23,866 and $ 45,962 for Coal, Gas and All Other, respectively.

Industry segment results for six months ended June 30, 2011 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	$	1,583,332	$	516,066	$	195,921	$	46,872		$	2,342,191	$	229,759	$	47,912	$	80,925		$	6,654		$	365,250	$	164,037	$	—		$	2,871,478
Sales—purchased gas	—		—		—		—			—		—		—		—			2,142			2,142		—		—			2,142
Sales—gas royalty interests	—		—		—		—			—		—		—		—			35,108			35,108		—		—			35,108
Freight—outside	—		—		—		96,440			96,440		—		—		—			—			—		—		—			96,440
Intersegment transfers	—		—		—		—			—		—		—		—			1,922			1,922		108,639		(110,561		)	—
Total Sales and Freight	$	1,583,332	$	516,066	$	195,921	$	143,312		$	2,438,631	$	229,759	$	47,912	$	80,925		$	45,826		$	404,422	$	272,676	$	(110,561	)	$	3,005,168
Earnings (Loss) Before Income Taxes	$	289,148	$	324,113	$	86,921	$	(249,340	)	$	450,842	$	79,570	$	12,882	$	(5,832	)	$	(34,198	)	$	52,422	$	2,573	$	(155,976	)	$	349,861	(E)
Segment assets										$	5,026,836											$	6,096,958	$	317,677	$	759,647		$	12,201,118	(F)
Depreciation, depletion and amortization										$	196,996											$	100,978	$	8,888	$	—		$	306,862
Capital expenditures										$	253,230											$	319,237	$	12,974	$	—		$	585,441

(E) Includes equity in earnings of unconsolidated affiliates of $8,702 , $1,001 and $1,609 for Coal, Gas and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $26,995 , $24,570 and $49,386 for Coal, Gas and All Other, respectively.

Industry segment results for six months ended June 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	$	1,462,319	$	275,602	$	113,022	$	29,161		$	1,880,104	$	310,347	$	18,382	$	32,752	$	3,095		$	364,576	$	144,950	$	—		$	2,389,630
Sales—purchased gas	—		—		—		—			—		—		—		—		4,756			4,756		—		—			4,756
Sales—gas royalty interests	—		—		—		—			—		—		—		—		28,490			28,490		—		—			28,490
Freight—outside	—		—		—		59,275			59,275		—		—		—		—			—		—		—			59,275
Intersegment transfers	—		—		—		—			—		—		—		—		1,562			1,562		87,170		(88,732		)	—
Total Sales and Freight	$	1,462,319	$	275,602	$	113,022	$	88,436		$	1,939,379	$	310,347	$	18,382	$	32,752	$	37,903		$	399,384	$	232,120	$	(88,732	)	$	2,482,151
Earnings (Loss) Before Income Taxes	$	247,731	$	133,376	$	58,964	$	(209,486	)	$	230,585	$	151,920	$	2,362	$	3,387	$	(29,791	)	$	127,878	$	9,624	$	(129,771	)	$	238,316	(G)
Segment assets										$	4,946,425										$	5,818,535	$	311,613	$	611,518		$	11,688,091	(H)
Depreciation, depletion and amortization										$	161,748										$	81,045	$	9,157	$	—		$	251,950
Capital expenditures										$	384,668										$	3,664,460	$	4,162	$	—		$	4,053,290

(G) Includes equity in earnings of unconsolidated affiliates of $6,428 , ($725) and $2,989 for Coal, Gas and All Other, respectively.

(H) Includes investments in unconsolidated equity affiliates of $17,296 , $23,866 and $45,962 for Coal, Gas and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2011			2010			2011			2010
Segment Earnings Before Income Taxes for total reportable business segments	$	180,396		$	171,688		$	503,264		$	358,463
Segment Earnings Before Income Taxes for all other businesses	4,422			6,255			2,573			9,624
Interest income (expense), net and other non-operating activity (I)	(67,339		)	(67,732		)	(136,625		)	(69,273		)
Acquisition and Financing Fees (I)	—			(14,187		)	—			(60,750		)
Evaluation fees for non-core asset dispositions (I)	(2,605		)	—			(3,261		)	—
Loss on debt extinguishment	(16,090		)	—			(16,090		)	—
Operating lease cease-use	—			124			—			252
Earnings Before Income Taxes	$	98,784		$	96,148		$	349,861		$	238,316



Total Assets:	June 30,
Total Assets:	2011		2010
Segment assets for total reportable business segments	$	11,123,794	$	10,764,960
Segment assets for all other businesses	317,677		311,613
Items excluded from segment assets:
Cash and other investments (I)	25,852		33,826
Recoverable income taxes	44,920		36,145
Deferred tax assets	636,193		488,278
Bond issuance costs	52,682		53,269
Total Consolidated Assets	$	12,201,118	$	11,688,091

_________________________

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000 , 8.000% per annum notes due April 1, 2017 , the $1,250,000 , 8.250% per annum notes due April 1, 2020 , and the $250,000 , 6.375% per annum notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all 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, 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.

Income Statement for the three months ended June 30, 2011 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	189,970	$	1,241,265		$	56,058	$	(1,293	)	$	1,486,000
Sales—Purchased Gas	—			1,162		—			—		—			1,162
Sales—Gas Royalty Interests	—			16,273		—			—		—			16,273
Freight—Outside	—			—		59,572			—		—			59,572
Other Income (including equity earnings)	149,780			2,635		10,216			9,355		(147,065		)	24,921
Total Revenue and Other Income	149,780			210,040		1,311,053			65,413		(148,358		)	1,587,928
Cost of Goods Sold and Other Operating Charges	34,424			75,383		717,439			53,718		46,435			927,399
Purchased Gas Costs	—			1,776		—			—		—			1,776
Loss on Debt Extinguishment	16,090			—		—			—		—			16,090
Gas Royalty Interests’ Costs	—			14,379		—			—		(13		)	14,366
Related Party Activity	704			—		(10,996		)	535		9,757			—
Freight Expense	—			—		59,572			—		—			59,572
Selling, General and Administrative Expense	—			28,218		63,591			317		(48,703		)	43,423
Depreciation, Depletion and Amortization	3,003			51,314		102,864			619		—			157,800
Abandonment of Long- Lived Assets	—			—		115,479			—		—			115,479
Interest Expense	59,286			2,552		2,841			14		(96		)	64,597
Taxes Other Than Income	1,883			8,269		77,760			730		—			88,642
Total Costs	115,390			181,891		1,128,550			55,933		7,380			1,489,144
Earnings (Loss) Before Income Taxes	34,390			28,149		182,503			9,480		(155,738		)	98,784
Income Tax Expense (Benefit)	(42,994		)	11,034		49,774			3,586		—			21,400
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	77,384		$	17,115	$	132,729		$	5,894	$	(155,738	)	$	77,384

Balance Sheet at June 30, 2011 (unaudited):



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	21,500	$	1,337		$	2,486		$	1,196	$	—		$	26,519
Accounts and Notes Receivable:
Trade	—		66,335			617			366,674		—			433,626
Securitized	70,000		—			—			—		—			70,000
Other	8,520		2,054			8,598			4,146		—			23,318
Inventories	—		5,457			205,439			48,767		—			259,663
Recoverable Income Taxes	10,028		34,892			—			—		—			44,920
Deferred Income Taxes	173,529		1,083			—			—		—			174,612
Prepaid Expenses	18,134		56,299			36,843			6,916		—			118,192
Total Current Assets	301,711		167,457			253,983			427,699		—			1,150,850
Property, Plant and Equipment:
Property, Plant and Equipment	175,828		6,628,614			8,241,997			24,484		—			15,070,923
Less-Accumulated Depreciation, Depletion and Amortization	97,997		728,475			3,983,272			16,631		—			4,826,375
Property, Plant and Equipment-Net	77,831		5,900,139			4,258,725			7,853		—			10,244,548
Other Assets:
Deferred Income Taxes	897,183		(435,602		)	—			—		—			461,581
Investment in Affiliates	8,374,149		24,570			923,072			16,641		(9,237,481		)	100,951
Restricted Cash	20,291		—			—			—		—			20,291
Other	117,960		41,019			53,478			10,440		—			222,897
Total Other Assets	9,409,583		(370,013		)	976,550			27,081		(9,237,481		)	805,720
Total Assets	$	9,789,125	$	5,697,583		$	5,489,258		$	462,633	$	(9,237,481	)	$	12,201,118
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	107,540	$	122,794		$	109,498		$	11,524	$	—		$	351,356
Accounts Payable (Recoverable)—Related Parties	2,646,374		—			(2,973,888		)	327,514		—			—
Short-Term Notes Payable	—		260,750			—			—		—			260,750
Current Portion Long-Term Debt	777		10,174			13,590			742		—			25,283
Borrowings under Securitization Facility	70,000		—			—			—		—			70,000
Other Accrued Liabilities	503,237		57,155			264,209			12,261		—			836,862
Total Current Liabilities	3,327,928		450,873			(2,586,591		)	352,041		—			1,544,251
Long-Term Debt:	3,000,952		54,081			125,855			1,359		—			3,182,247
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			3,085,834			—		—			3,085,834
Pneumoconiosis Benefits	—		—			175,523			—		—			175,523
Mine Closing	—		—			401,439			—		—			401,439
Gas Well Closing	—		61,650			54,446			—		—			116,096
Workers’ Compensation	—		—			148,917			108		—			149,025
Salary Retirement	136,366		—			—			—		—			136,366
Reclamation	—		—			46,661			—		—			46,661
Other	104,701		27,757			17,164			5		—			149,627
Total Deferred Credits and Other Liabilities	241,067		89,407			3,929,984			113		—			4,260,571
Total CONSOL Energy Inc. Stockholders’ Equity	3,219,178		5,108,351			4,020,010			109,120		(9,237,481		)	3,219,178
Noncontrolling Interest	—		(5,129		)	—			—		—			(5,129		)
Total Liabilities and Stockholders’ Equity	$	9,789,125	$	5,697,583		$	5,489,258		$	462,633	$	(9,237,481	)	$	12,201,118

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



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	192,124	$	982,731		$	46,714	$	(1,453	)	$	1,220,116
Sales—Purchased Gas	—			1,740		—			—		—			1,740
Sales—Gas Royalty Interests	—			14,151		—			—		—			14,151
Freight—Outside	—			—		28,075			—		—			28,075
Other Income (including equity earnings)	131,063			528		14,450			7,941		(128,717		)	25,265
Total Revenue and Other Income	131,063			208,543		1,025,256			54,655		(130,170		)	1,289,347
Cost of Goods Sold and Other Operating Charges	23,114			59,087		684,569			43,897		8,104			818,771
Purchased Gas Costs	—			1,339		—			—		—			1,339
Acquisition and Financing Fees	14,187			3,328		—			—		—			17,515
Gas Royalty Interests’ Costs	—			11,544		—			—		(16		)	11,528
Related Party Activity	745			—		(2,883		)	538		1,600			—
Freight Expense	—			—		28,075			—		—			28,075
Selling, General and Administrative Expense	—			21,361		26,026			353		(8,695		)	39,045
Depreciation, Depletion and Amortization	2,425			48,953		80,725			661		—			132,764
Interest Expense	60,248			2,108		2,769			5		(92		)	65,038
Taxes Other Than Income	2,864			6,722		68,824			714		—			79,124
Total Costs	103,583			154,442		888,105			46,168		901			1,193,199
Earnings (Loss) Before Income Taxes	27,480			54,101		137,151			8,487		(131,071		)	96,148
Income Tax Expense (Benefit)	(39,188		)	20,608		40,271			3,557		—			25,248
Net Income (Loss)	66,668			33,493		96,880			4,930		(131,071		)	70,900
Less: Net Income Attributable to Noncontrolling Interest	—			—		—			—		(4,232		)	(4,232		)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	66,668		$	33,493	$	96,880		$	4,930	$	(135,303	)	$	66,668

Balance Sheet at December 31, 2010 :



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	11,382		$	16,559		$	3,235		$	1,618	$	—		$	32,794
Accounts and Notes Receivable:
Trade	—			65,197			646			186,687		—			252,530
Securitized	200,000			—			—			—		—			200,000
Other	4,635			3,361			10,915			2,678		—			21,589
Inventories	—			4,456			203,962			50,120		—			258,538
Recoverable Income Taxes	(3,189		)	35,717			—			—		—			32,528
Deferred Income Taxes	173,211			960			—			—		—			174,171
Prepaid Expenses	35,297			57,907			39,309			10,343		—			142,856
Total Current Assets	421,336			184,157			258,067			251,446		—			1,115,006
Property, Plant and Equipment:
Property, Plant and Equipment	166,884			6,336,121			8,422,235			26,118		—			14,951,358
Less-Accumulated Depreciation, Depletion and Amortization	91,952			628,506			4,083,693			17,956		—			4,822,107
Property, Plant and Equipment-Net	74,932			5,707,615			4,338,542			8,162		—			10,129,251
Other Assets:
Deferred Income Taxes	902,188			(417,342		)	—			—		—			484,846
Investment in Affiliates	7,833,948			23,569			943,674			11,087		(8,718,769		)	93,509
Restricted Cash	20,291			—			—			—		—			20,291
Other	118,149			37,268			61,532			10,758		—			227,707
Total Other Assets	8,874,576			(356,505		)	1,005,206			21,845		(8,718,769		)	826,353
Total Assets	$	9,370,844		$	5,535,267		$	5,601,815		$	281,453	$	(8,718,769	)	$	12,070,610
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	130,063		$	101,944		$	113,036		$	8,968	$	—		$	354,011
Accounts Payable (Recoverable)-Related Parties	2,363,108			30,302			(2,543,991		)	150,581		—			—
Short-Term Notes Payable	155,000			129,000			—			—		—			284,000
Current Portion Long-Term Debt	758			9,851			13,589			585		—			24,783
Borrowings under Securitization Facility	200,000			—			—			—		—			200,000
Other Accrued Liabilities	302,788			59,960			425,735			13,508		—			801,991
Total Current Liabilities	3,151,717			331,057			(1,991,631		)	173,642		—			1,664,785
Long-Term Debt:	3,000,702			58,905			125,627			904		—			3,186,138
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—			—			3,077,390			—		—			3,077,390
Pneumoconiosis Benefits	—			—			173,616			—		—			173,616
Mine Closing	—			—			393,754			—		—			393,754
Gas Well Closing	—			60,027			70,951			—		—			130,978
Workers’ Compensation	—			—			148,265			49		—			148,314
Salary Retirement	161,173			—			—			—		—			161,173
Reclamation	—			—			53,839			—		—			53,839
Other	112,775			25,483			6,352			—		—			144,610
Total Deferred Credits and Other Liabilities	273,948			85,510			3,924,167			49		—			4,283,674
Total CONSOL Energy Inc. Stockholders’ Equity	2,944,477			5,068,259			3,543,652			106,858		(8,718,769		)	2,944,477
Noncontrolling Interest	—			(8,464		)	—			—		—			(8,464		)
Total Liabilities and Stockholders’ Equity	$	9,370,844		$	5,535,267		$	5,601,815		$	281,453	$	(8,718,769	)	$	12,070,610

Income Statement for the six months ended June 30, 2011 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	367,172	$	2,396,615		$	110,154	$	(2,463	)	$	2,871,478
Sales—Purchased Gas	—			2,142		—			—		—			2,142
Sales—Gas Royalty Interests	—			35,108		—			—		—			35,108
Freight—Outside	—			—		96,440			—		—			96,440
Other Income (including equity earnings)	396,644			4,315		21,637			18,596		(393,055		)	48,137
Total Revenue and Other Income	396,644			408,737		2,514,692			128,750		(395,518		)	3,053,305
Cost of Goods Sold and Other Operating Charges	63,400			146,782		1,376,956			107,705		46,265			1,741,108
Purchased Gas Costs	—			2,452		—			—		—			2,452
Loss on Debt Extinguishment	16,090			—		—			—		—			16,090
Gas Royalty Interests’ Costs	—			31,200		—			—		(27		)	31,173
Related Party Activity	(2,536		)	—		(12,737		)	1,001		14,272			—
Freight Expense	—			—		96,251			—		—			96,251
Selling, General and Administrative Expense	—			53,787		77,935			600		(48,703		)	83,619
Depreciation, Depletion and Amortization	5,364			100,978		199,272			1,248		—			306,862
Abandonment of Long-Lived Assets	—			—		115,479			—		—			115,479
Interest Expense	120,428			5,232		5,583			27		(191		)	131,079
Taxes Other Than Income	3,386			16,076		158,274			1,595		—			179,331
Total Costs	206,132			356,507		2,017,013			112,176		11,616			2,703,444
Earnings (Loss) Before Income Taxes	190,512			52,230		497,679			16,574		(407,134		)	349,861
Income Tax Expense (Benefit)	(79,021		)	20,469		132,611			6,269		—			80,328
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	269,533		$	31,761	$	365,068		$	10,305	$	(407,134	)	$	269,533

Income Statement for the six months ended June 30, 2010 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	366,137	$	1,928,808		$	97,170	$	(2,485	)	$	2,389,630
Sales—Purchased Gas	—			4,756		—			—		—			4,756
Sales—Gas Royalty Interests	—			28,490		—			—		—			28,490
Freight—Outside	—			—		59,275			—		—			59,275
Other Income (including equity earnings)	278,397			1,424		22,485			14,249		(269,299		)	47,256
Total Revenue and Other Income	278,397			400,807		2,010,568			111,419		(271,784		)	2,529,407
Cost of Goods Sold and Other Operating Charges	42,722			108,116		1,313,671			91,391		29,733			1,585,633
Purchased Gas Costs	—			3,647		—			—		—			3,647
Acquisition and Financing Fees	60,750			3,328		—			—		—			64,078
Gas Royalty Interests’ Costs	—			23,758		—			—		(33		)	23,725
Related Party Activity	(1,238		)	—		(4,865		)	968		5,135			—
Freight Expense	—			—		59,275			—		—			59,275
Selling, General and Administrative Expense	—			37,692		61,365			640		(30,522		)	69,175
Depreciation, Depletion and Amortization	5,829			81,045		163,736			1,340		—			251,950
Interest Expense	63,998			4,023		5,335			10		(183		)	73,183
Taxes Other Than Income	5,403			11,503		142,038			1,481		—			160,425
Total Costs	177,464			273,112		1,740,555			95,830		4,130			2,291,091
Earnings (Loss) Before Income Taxes	100,933			127,695		270,013			15,589		(275,914		)	238,316
Income Tax Expense (Benefit)	(66,004		)	48,575		71,066			5,897		—			59,534
Net Income (Loss)	$	166,937		$	79,120	$	198,947		$	9,692	$	(275,914	)	$	178,782
Less: Net Income Attributable to Noncontrolling Interest	$	—		$	—	$	—		$	—	$	(11,845	)	$	(11,845	)
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	166,937		$	79,120	$	198,947		$	9,692	$	(287,759	)	$	166,937

Cash Flow for the Six Months Ended June 30, 2011 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by (Used in) Operating Activities	$	370,780		$	182,364		$	243,823		$	(1,484	)	$	—	$	795,483
Cash Flows from Investing Activities:
Capital Expenditures	$	(12,974	)	$	(319,237	)	$	(253,230	)	$	—		$	—	$	(585,441	)
Net Investment in Equity Affiliates	—			—			3,870			—			—		3,870
Other Investing Activities	10			1,106			4,897			1,467			—		7,480
Net Cash (Used in) Provided by Investing Activities	$	(12,964	)	$	(318,131	)	$	(244,463	)	$	1,467		$	—	$	(574,091	)
Cash Flows from Financial Activities:
Dividends Paid	$	(45,293	)	$	—		$	—		$	—		$	—	$	(45,293	)
(Payments On) Proceeds from Short-Term Borrowings	(155,000		)	131,750			—			—			—		(23,250		)
Payments on Securitization Facility	(130,000		)	—			—			—			—		(130,000		)
Payments on Long Term Notes, including redemption premium	(265,785		)	—			—			—			—		(265,785		)
Proceeds from Long-Term Notes	250,000			—			—			—			—		250,000
Debt Issuance and Financing Fees	(10,360		)	(5,067		)	—			—			—		(15,427		)
Other Financing Activities	8,740			(6,138		)	(109		)	(405		)	—		2,088
Net Cash (Used in) Provided by Financing Activities	$	(347,698	)	$	120,545		$	(109	)	$	(405	)	$	—	$	(227,667	)

Cash Flow for the Six Months Ended June 30, 2010 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(3,536,558	)	$	173,558		$	3,868,135		$	707		$	—	$	505,842
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(188,795	)	$	(388,830	)	$	—		$	—	$	(577,625	)
Net Investment in Equity Affiliates	—			—			5,101			—			—		5,101
Acquisition of Dominion Exploration and Production Business	—			—			(3,475,665		)	—			—		(3,475,665		)
Purchase of CNX Gas Noncontrolling Interest	(991,034		)	—			—			—			—		(991,034		)
Other Investing Activities	—			45			2,442			—			—		2,487
Net Cash Used in Investing Activities	$	(991,034	)	$	(188,750	)	$	(3,856,952	)	$	—		$	—	$	(5,036,736	)
Cash Flows from Financial Activities:
Dividends Paid	$	(40,694	)	$	—		$	—		$	—		$	—	$	(40,694	)
Proceeds from (Payments on) Short-Term Borrowings	(122,800		)	8,500			—			—			—		(114,300		)
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	(80,567		)	8,644			(8,644		)	—			—		(80,567		)
Other Financing Activities	11,600			(2,035		)	(3,009		)	(257		)	—		6,299
Net Cash Provided by (Used in) Financing Activities	$	4,496,401		$	15,109		$	(11,653	)	$	(257	)	$	—	$	4,499,600


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

General

Second quarter demand for U.S. thermal and metallurgical coal continued the strong pace set in the first quarter. Continued international demand for U.S. thermal coals has offset flat demand from domestic electric generators. In addition, demand for metallurgical coals continues to be strong domestically and very strong as an export product.

International demand for U.S. thermal coal continued to show resiliency through the second quarter. Average prices for spot coal delivered into Europe increased slightly from the first quarter. These coals are currently competing with metallurgical coals for available space at U.S. East Coast terminals. Investments in port facilities, including CONSOL Energy's Baltimore Terminal, and rail capacity should allow thermal coal exports to grow in coming years to meet expected demand growth in Europe. This demand growth will be spurred by expected retirements of European nuclear plants, the phase-out of subsidized mining in Europe and backfilling for South African and Colombian coals that are being pulled into Asian markets. U.S. coals will be a likely replacement for this lost fuel.

Domestically, June coal inventories at electric generators were 10 to 13 million tons below year ago levels. U.S. electric demand during the second quarter of 2011 was estimated to be slightly below 2010 levels due to mild weather and moderate economic growth. Although forecasts have indicated a normal cooling season, early results show a potential increase in demand for electric generation during the 2011 summer season.

Metallurgical coal demand grew during the second quarter as world blast furnace output was 3.1% greater than the first quarter and 4.9% greater for the the first half of 2011 compared to the same period of 2010. Chinese steel production is up 6.2% for the first half of 2011 compared to the same period in 2010. U.S. demand from steelmakers has been resilient despite the recent slowdown in one of their largest markets - U.S. auto sales. Part shortages from Japanese suppliers impacted by the earthquake in Japan have created global supply chain disruptions for automakers. Sales in the second half of 2011 are expected to improve as supply chain issues are resolved resulting in higher production driving steel demand.

Supply for metallurgical coal continues to remain tight due to ongoing problems bringing Australian mines back into full production after the latest flooding and production issues at several major U.S. metallurgical mines. The strong global demand for steel combined with a tight supply situation for metallurgical coal has created a very strong market for metallurgical coal. CONSOL Energy is well positioned to take advantage of this market with its low cost Buchanan low-volatile operation and low cost high-volatile operations in Northern Appalachia.

Natural gas markets continue to grow beyond pre-recession levels and demand for the first half of 2011 is estimated to be 2.2% greater than comparable 2010 levels. However, supply has increased even faster than demand due to the prolific nature of new shale resources. This supply / demand imbalance is being brought back into balance in the short term by decreased imports from liquefied natural gas (LNG) and Western Canadian pipeline imports as well as increased exports to Eastern Canada and Mexico. Longer-term rebalancing will be aided by declining conventional production and the shift in drilling towards oil and “liquids rich” gas plays. CONSOL Energy believes that the U.S. gas markets will return to equilibrium in the next one to two years.

Longer-term prospects for natural gas markets remain appealing as the U.S. continues to build more high-efficiency gas electric power plants and gas consumption increases in the petrochemical industry and developing sources of demand such as more wide-scale use of natural gas vehicles. CONSOL Energy continues to believe that natural gas will bring balance to CONSOL Energy's portfolio of long-lived energy resources.

CONSOL Energy engaged in several business and financing transactions in the six months ended June 30, 2011. These transactions include the following:

•

In June 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collective bargaining agreement which will run from July 1, 2011 to December 31, 2016. That agreement, National Bituminous Coal Wage Agreement of 2011 (2011 NBCWA) covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA that was set to expire on December 31, 2011. Key elements of the new agreement include the following items:


a.	A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1 ^st throughout the contract term.

Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. In accordance with the Pension Relief Act, the 1974 Pension Plan's Pension Protection Act zone status was recertified to the "green" zone status for the plan year beginning July 1, 2010. New inexperienced miners hired after December 31, 2011 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-16) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of experience will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-16) to the CDSP beginning January 1, 2012. All current UMWA represented employees will be given the opportunity to opt-out of future participation in the 1974 Pension Plan and instead participate in the CDSP.


c.	A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.


d.	An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.


e.	Various other changes related to absenteeism, contribution to various UMWA benefit funds, eligibility for various vacation days and sick days.

The total incremental cost of the revised terms of the contract over 2010 operating costs at CONSOL Energy's represented operations is projected to average approximately 3.5% per ton, per year over the term of the contract. CONSOL Energy expects a similar increase to impact all of CONSOL Energy's tons due to cost inflation that typically occurs at CONSOL Energy's non-represented mines.

•

In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle status since March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided it was in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The Company redeployed all the movable equipment that could be used at other locations. The abandonment of this underground facility resulted in a $115 million charge to pre-tax earnings in June 2011. See Note 8—Property, Plant and Equipment in the Notes to the Consolidated Financial Statements of this Form 10-Q for additional disclosure. The Company expects the closure of Mine 84 to result in pre-tax cash savings of $18 million per year.


•	In April 2011, CNX Gas entered into an amendment of its senior secured credit agreement which increases the availability under the agreement from $700 million to $1.0 billion, decreases the interest rate and extends the term from May 6, 2014 to April 12, 2016. The amended credit agreement continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries.


•	In April 2011, CONSOL Energy amended and extended its existing $1.5 billion senior secured credit agreement, which decreases the interest rate and extends the term from May 7, 2014 to April 12, 2016. The amended agreement continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries.

•

On March 9, 2011, CONSOL Energy issued $250 million of 6.375% senior notes due March 2021. The Notes are guaranteed by substantially all of the Company's existing and future wholly owned domestic restricted subsidiaries. The Company issued the Notes with the intention of using the net proceeds to repay its outstanding 7.875% senior secured notes due March 1, 2012, on or before their maturity. On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing the notes. By using the proceeds of the $250 million, 6.375% senior Notes due March 2021 to affect this redemption, the Company effectively extended the maturity of the $250 million of long-term indebtedness nine years at a lower interest rate. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million, for a total redemption cost of approximately $268 million. The loss on

extinguishment of debt was approximately $16 million, which primarily represents the interest that would have been paid on these notes if they had been held to maturity.

CONSOL Energy is managing several significant matters that may affect our business and impact our financial results in the future including the following:

•

Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel and synthetic rubber that we use in our operations, (ii) continued scrutiny of existing safety regulations and the development of new safety regulations, and (iii) potential changes and more stringent application of rules related to subsidence to surface structures and streams.

•

Federal and state environmental regulators are reviewing our operations more closely and more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the U.S. Environmental Protection Agency and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million; in 2011 we plan to complete construction of pipelines to convey mine water from our Shoemaker Mine and the closed Windsor Mine to approved mixing zones in the Ohio River; and we are experiencing delays in obtaining stream crossing permits that are required for the construction of gathering lines which are necessary for moving gas from our Marcellus Shale wells to market.

•

On April 19, 2011 the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from Marcellus Shale operators. They called on operators to cease delivering wastewater to the POTWs by May 19, 2011. CONSOL Energy has implemented a re-cycle and re-use process of its Marcellus derived water for fracing operations, and will only safely dispose of Marcellus wastewater in regulated, underground injection control wells.


•	CONSOL Energy continues to explore potential sales of non-core assets and options for monetizing a portion of its shale assets.

Results of Operations

Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $77 million, or $0.34 per diluted share, for the three months ended June 30, 2011 . Net income attributable to CONSOL Energy shareholders was $67 million, or $0.29 per diluted share, for the three months ended June 30, 2010 .

The coal division includes steam coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $152 million of earnings before income tax for the three months ended June 30, 2011 compared to $117 million for the three months ended June 30, 2010 . The total coal division sold 16.2 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, for the three months ended June 30, 2011 compared to 15.7 million tons for the three months ended June 30, 2010 .

The average sales price and total costs per ton for all active coal operations were as follows:



	For the Three Months Ended June 30,
	2011		2010		Variance		Percent Change
Average Sales Price per ton sold	$	73.08	$	60.71	$	12.37	20.4	%
Average Costs per ton sold	52.19		47.17		5.02		10.6	%
Margin	$	20.89	$	13.54	$	7.35	54.3	%

The higher average sales price per ton sold reflects successful renegotiation of several domestic steam contracts whose pricing took effect January 1, 2011, another strong quarter of high volatile metallurgical coal sales and continued demand for our premium low volatile metallurgical coal. Also, 3.4 million tons were sold on the export market at an average sales price of $119.71 per ton for the three months ended June 30, 2011 compared to 2.1 million tons at an average price of $99.73 per ton for the three months ended June 30, 2010.

Average costs per ton sold have increased in the period-to-period comparison due primarily to higher operating supplies and maintenance costs due to additional maintenance and equipment overhaul costs, additional roof control costs and higher costs associated with the sales price of coal sold, such as royalties and production related taxes. Also, depreciation, depletion and amortization costs increased due to assets placed in service after the 2010 period and expenses related to other post employment benefits and pension increased as discussed below.

The total gas division includes coalbed methane (CBM), conventional, Marcellus and other gas. The total gas division contributed $28 million of earnings before income tax for the three months ended June 30, 2011 compared to $54 million for the three months ended June 30, 2010 . Total gas production was 37.5 billion cubic feet for the three months ended June 30, 2011 compared to 31.9 billion cubic feet for the three months ended June 30, 2010 .

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



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	5.07	$	6.03	$	(0.96	)	(15.9	)%
Average Costs per thousand cubic feet sold	3.86		3.75		0.11			2.9	%
Margin	$	1.21	$	2.28	$	(1.07	)	(46.9	)%

Total gas division outside sales revenue was $190 million for the three months ended June 30, 2011 compared to $192 million for the three months ended June 30, 2010 . The decrease was primarily due to the 15.9% reduction in average sales price, offset, in part, by the 17.6% increase in volumes sold. The decrease in average sales price is the result of various gas swap transactions maturing in each period and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 23.1 billion cubic feet of our produced gas sales volumes for the three months ended June 30, 2011 at an average price of $5.14 per thousand cubic feet. These financial hedges represented 13.6 billion cubic feet of our produced gas sales volumes for the three months ended June 30, 2010 at an average price of $8.15 per thousand cubic feet.

Total gas unit costs increased slightly for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 primarily due to the impact of the higher cost structure of the producing wells purchased in the Dominion Acquisition. The purchased Dominion wells increased total operating costs by $0.33 per thousand cubic feet due to higher costs and lower volumes produced related to the age of these wells compared to the legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.22 per thousand cubic feet primarily due to the additional volumes produced and improved depreciation, depletion and amortization. Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition. Lower depreciation, depletion and amortization rates were the result of the higher proportion of gas reserves compared to capital placed in service after the 2010 period.

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.

Included in both coal and gas unit costs are Selling, General and Administrative Expenses and total Company long-term liabilities, such as post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability. A detailed analysis of these total Company expenses are as follows:

Total Company Selling, General and Administrative Expenses are allocated to various segments primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. Total Company Selling, General and Administrative Expenses were made up of the following items:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Employee wages and related expenses	$	20	$	18	$	2		11.1	%
Advertising and promotion	3		1		2			200.0	%
Commissions	4		5		(1		)	(20.0	)%
Consulting and professional services	6		8		(2		)	(25.0	)%
Miscellaneous	10		7		3			42.9	%
Total Company Selling, General and Administrative Expenses	$	43	$	39	$	4		10.3	%

Total Company selling, general and administrative expenses increased due to the following:


•	Employee wages and related expenses increased $2 million which was primarily attributable to additional hiring of support staff in the period-to-period comparison.


•	Advertising and promotion expense increased $2 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.


•	Commission expense decreased $1 million in the period-to-period comparison due to the mix of coal brokers utilized.


•	Consulting and professional services decreased $2 million due to various corporate projects that occurred throughout both periods, none of which were individually material.


•	Miscellaneous selling, general and administrative expenses increased $3 million primarily due to various corporate projects that occurred throughout both periods, none of which were individually material.

Total Company long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial liabilities was $90 million for the three months ended June 30, 2011 compared to $73 million for the three months ended June 30, 2010. The increase of $17 million for total CONSOL Energy was due primarily to a revision to the OPEB and salary pension expense. The additional OPEB and salary pension expense related to employees retiring sooner than originally anticipated and average claim costs being higher than originally anticipated. These changes resulted in a year-to-date adjustment of approximately $14 million. Also, higher long-term liability expenses in the period-to-period comparison were due to changes in the discount rates used at the measurement date, which is December 31. See Note 3—Components of Pension 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 Notes to the Condensed Consolidated Financial Statements for additional detail of total Company expense increases.

TOTAL COAL SEGMENT ANALYSIS for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 :

The coal segment contributed $ 152 million of earnings before income tax for the three months ended June 30, 2011 compared to $ 117 million for the three months ended June 30, 2010 . Variances by the individual coal segments are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	June 30, 2011											June 30, 2010
	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	$	781	$	118	$	279	$	7		$	1,185	$	36		$	62	$	129	$	3		$	230
Purchased Coal	—		—		—		27			27		—			—		—		26			26
Total Outside Sales	781		118		279		34			1,212		36			62		129		29			256
Freight Revenue	—		—		—		59			59		—			—		—		31			31
Other Income	1		3		—		14			18		(2		)	1		—		(2		)	(3		)
Total Revenue and Other Income	782		121		279		107			1,289		34			63		129		58			284
Costs and Expenses:
Total operating costs	495		53		70		75			693		1			30		20		21			72
Total provisions	59		6		10		22			97		12			3		4		(16		)	3
Total administrative & other costs	42		5		6		24			77		2			4		1		3			10
Depreciation, depletion and amortization	76		10		9		116			211		13			7		4		109			133
Total Costs and Expenses	672		74		95		237			1,078		28			44		29		117			218
Freight Expense	—		—		—		59			59		—			—		—		31			31
Total Costs	672		74		95		296			1,137		28			44		29		148			249
Earnings (Loss) Before Income Taxes	$	110	$	47	$	184	$	(189	)	$	152	$	6		$	19	$	100	$	(90	)	$	35

STEAM COAL SEGMENT

The steam coal segment contributed $ 110 million to total Company earnings before income tax for the three months ended June 30, 2011 compared to $ 104 million for the three months ended June 30, 2010 . The steam coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced Steam Tons Sold (in millions)	13.2		13.9		(0.7		)	(5.0	)%
Average Sales Price Per Steam Ton Sold	$	58.97	$	53.57	$	5.40		10.1	%
Average Operating Costs Per Steam Ton Sold	$	37.49	$	35.41	$	2.08		5.9	%
Average Provision Costs Per Steam Ton Sold	$	4.42	$	3.38	$	1.04		30.8	%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	3.16	$	2.88	$	0.28		9.7	%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	5.73	$	4.59	$	1.14		24.8	%
Total Average Costs Per Steam Ton Sold	$	50.80	$	46.26	$	4.54		9.8	%
Margin Per Steam Ton Sold	$	8.17	$	7.31	$	0.86		11.8	%

Steam coal revenue was $ 781 million for the three months ended June 30, 2011 compared to $ 745 million for the three months ended June 30, 2010 . The $ 36 million increase was attributable to a $5.40 per ton higher average sales prices, offset, in part by 0.7 million fewer tons sold. The higher average steam coal sales price in the 2011 period was the result of successful renegotiation of several domestic steam contracts whose pricing took effect on January 1, 2011. Also, 0.8 million tons of steam coal was sold on the export market at an average sales price of $67.17 per ton for the three months ended June 30, 2011 compared to 0.6 million tons at an average price of $63.84 per ton for the three months ended June 30, 2010. Fewer steam tons sold were primarily due to the 1.5 million tons of steam coal sold on the high volatile metallurgical coal market for the three months ended June 30, 2011, which was an increase of 0.8 million tons compared to the three months ended June 30, 2010. Produced steam coal inventory was 1.6 million tons at June 30, 2011 compared to 2.9 million tons at June 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 comprised 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 $495 million in the three months ended June 30, 2011 compared to $494 million in the three months ended June 30, 2010. Operating costs related to the steam coal segment have increased primarily due to higher average cost per ton sold, offset, in part, by lower volumes sold.

Changes in the average operating costs per ton for steam coal sold were primarily related to the following items:


•	Average operating costs per steam ton sold increased due to fewer tons sold. Fixed costs are allocated over less tons; therefore, unit costs increased.

•

Average operating supplies & maintenance cost per ton sold increased due to additional maintenance and equipment overhaul costs, additional roof control costs and higher fuel costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Fuel costs have also increased in the period-to-period comparison which resulted in a higher average cost per ton sold.


•	Production taxes average cost per ton sold increased due to the $5.40 per ton higher average sales price.


•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs have also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

•

Labor and related benefits average costs per ton sold were impaired, although total dollars expensed for these items was improved slightly. Average costs per ton sold were impacted by the 0.7 million ton reduction in sales tons. Labor benefit costs were impacted by the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding

of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover the benefits. This improvement was offset by higher contributions made to the 1974 Pension Trust (the Trust), which is a multi-employer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate has increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Reductions were also offset, in part, by additional employees in the period-to-period comparison.


•	These increases in average operating costs per ton for steam coal were offset, in part, by lower contract mining fees. Fewer contractors were retained to mine our reserves in the period-to-period comparison without a corresponding reduction in total steam coal sold which has resulted in lower average unit costs per ton sold.

Provision costs are comprised of the expenses related to the Company's long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and 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 are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. The average provision costs attributable to the steam coal segment were $59 million for the three months ended June 30, 2011 compared to $47 million for the three months ended June 30, 2010. The increase in the steam coal provision expense was attributable to the total company increased long-term liability expense as discussed in the total Company results of operations section. Also, steam coal accretion expense related to mine closing and related liabilities resulted in approximately $1 million additional expense for the period-to-period comparison. The increase related to the results of the annual engineering survey adjustments that were reflected in both periods. The 0.7 million ton reduction in sales volumes also contributed to the higher average unit costs per ton sold.

Selling, administrative and other costs attributable to the steam coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to various segments 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. Selling, administrative and other costs related to the steam coal segment were $42 million for the three months ended June 30, 2011 compared to $40 million for the three months ended June 30, 2010. The cost increases attributable to the steam coal segment were attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due to additional support staff in the period-to-period comparison. Higher average unit costs were also related to lower volumes of coal sold. Costs were allocated over less tons; therefore, unit costs increased.

Depreciation, depletion and amortization for the steam coal segment was $76 million for the three months ended June 30, 2011 compared to $63 million for the three months ended June 30, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for steam coal mines due to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. These higher expenses coupled with fewer tons sold resulted in a $1.14 increase in average costs per ton sold.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $47 million to total company earnings before income tax for the three months ended June 30, 2011 compared to $28 million for the three months ended June 30, 2010. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced High Vol Met Tons Sold (in millions)	1.5		0.7		0.8			114.3	%
Average Sales Price Per High Vol Met Ton Sold	$	78.84	$	75.52	$	3.32		4.4	%
Average Operating Costs Per High Vol Met Ton Sold	$	35.08	$	30.51	$	4.57		15.0	%
Average Provision Costs Per High Vol Met Ton Sold	$	4.18	$	3.20	$	0.98		30.6	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	3.63	$	2.81	$	0.82		29.2	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	6.36	$	4.37	$	1.99		45.5	%
Total Average Costs Per High Vol Met Ton Sold	$	49.25	$	40.89	$	8.36		20.4	%
Margin Per High Vol Met Ton Sold	$	29.59	$	34.63	$	(5.04	)	(14.6	%)

High volatile metallurgical coal revenue was $118 million for the three months ended June 30, 2011 compared to $56 million for the three months ended June 30, 2010. Strength in the metallurgical coal market has continued to allow the export of Northern Appalachian coal, historically sold domestically on the steam coal market, to crossover to the Brazilian and Asian metallurgical coal markets. Average sales prices for high volatile metallurgical coal have increased due to growing the base of end user customers.

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

Operating costs related to the high volatile metallurgical coal segment were $53 million for the three months ended June 30, 2011 compared to $23 million for the three months ended June 30, 2010. Operating costs related to the high volatile metallurgical coal segment have increased primarily due to higher volumes sold and higher average costs per ton sold.

Changes in average operating costs per ton for high volatile metallurgical coal sold is primarily related to the following items:

•

Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Higher non-union benefit rates for active employees were related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Increased labor and related benefit costs per unit sold were offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.

•

Average operating supplies & maintenance cost per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison.


•	Production taxes average cost per ton sold increased due to the $3.32 per ton higher average sales price.


•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.


•	Average preparation plant costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.


•	Average royalty costs per ton sold were lower in the period-to-period comparison due to fewer tons being mined from coal tracts that have a royalty, offset, in part, by higher average sales prices.


•	Average operating costs per ton sold decreased due to higher tons sold. Fixed costs were allocated over more tons; therefore, unit costs decreased.

The provision expense attributable to the high volatile metallurgical coal segment was $6 million for the three months ended June 30, 2011 compared to $3 million for the three months ended June 30, 2010. The increase in the high volatile metallurgical coal provision expense was attributable to the total Company increase in long-term liability expense discussed in the total Company results of operations section. The per unit impairment was offset, in part, by additional tons sold in the period-to-period comparison. Also, high volatile metallurgical coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison which contributed to lower costs per ton sold.

Selling, administrative and other costs attributable to the high volatile metallurgical coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative expenses, excluding commission expense, are allocated to various segments 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. Selling, administrative and other costs related to the high volatile metallurgical coal segment were $5 million for the three months ended June 30, 2011 compared to $1 million for the three months ended June 30, 2010. The cost increase attributable to the high volatile metallurgical coal segment is attributable to higher total Company selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due to additional support staff in the period-to-period comparison. These increases in expense increased costs per ton sold and were offset, in part, by higher volumes of high volatile metallurgical coal sold.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $10 million for the three months ended June 30, 2011 compared to $3 million for the three months ended June 30, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for high volatile metallurgical coal mines related to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. These increases in unit costs per ton sold were offset, in part, by additional high volatile metallurgical tons sold which lowered the unit cost per ton impact.

The high volatile metallurgical coal segment 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 volatile metallurgical coal segment contributed $184 million to total Company earnings before income tax for the three months ended June 30, 2011 compared to $84 million for the three months ended June 30, 2010. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)	1.4		1.0		0.4			40.0	%
Average Sales Price Per Low Vol Met Ton Sold	$	202.36	$	149.38	$	52.98		35.5	%
Average Operating Costs Per Low Vol Met Ton Sold	$	50.03	$	48.01	$	2.02		4.2	%
Average Provision Costs Per Low Vol Met Ton Sold	$	7.27	$	6.67	$	0.60		9.0	%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	4.80	$	5.11	$	(0.31	)	(6.1	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	6.62	$	4.67	$	1.95		41.8	%
Total Average Costs Per Low Vol Met Ton Sold	$	68.72	$	64.46	$	4.26		6.6	%
Margin Per Low Vol Met Ton Sold	$	133.64	$	84.92	$	48.72		57.4	%

Low volatile metallurgical coal revenue was $279 million for the three months ended June 30, 2011 compared to $150 million for the three months ended June 30, 2010. The $129 million increase was attributable to a $52.98 per ton higher average sales price due to the continued strengthening of the low volatile metallurgical market, both domestic and foreign. The continued strength of these markets is related to continued worldwide demand for premium low volatile metallurgical coal. CONSOL Energy sold 1.1 million tons of low volatile metallurgical coal in the export market at an average sales price of $209.85 per ton for the three months ended June 30, 2011 compared to 0.7 million tons at an average price of $153.25 for the three months ended June 30, 2010. Produced low volatile metallurgical coal inventory was 0.2 million tons at June 30, 2011 compared to 0.1 million tons at June 30, 2010.

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 volatile metallurgical coal segment were $70 million for the three months ended June 30, 2011 compared to $50 million for the three months ended June 30, 2010. Operating costs related to the low volatile metallurgical coal segment increased primarily due to higher average operating costs per ton sold and higher volumes sold.

Changes in average operating costs per ton sold of low volatile metallurgical coal were primarily related to the following items:


•	Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.

•

Average operating supplies and maintenance costs per ton sold increased due to additional roof control, additional ventilation of coalbed methane gas and additional equipment overhaul costs. Additional roof control costs result from changes in roof support strategy, such as types of roof support used and quantity of support put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period.


•	Coal inventory volumes and carrying value remained relatively consistent at June 30, 2011 compared to March 31, 2011. Coal inventory volumes remained consistent at June 30, 2010 compared to March 31, 2010 although inventory carrying values declined. These changes in inventory caused an increase in average operating cost per ton sold in the period-to-period comparison.


•	Average operating costs per low volatile metallurgical tons sold decreased due to higher tons sold. Fixed costs are then spread over more tons, thereby decreasing unit costs.


•	Labor and related benefits were improved on a cost per ton sold basis due to higher volumes sold. Labor and related benefit dollars spent were higher for the 2011 period compared to the 2010 period due to additional employees and increased non-union benefit rates for active employees which were related to the continued increase in healthcare costs.


•	Preparation plant and power average costs per ton sold were improved primarily due to higher tons sold.

The provision expense attributable to the low volatile metallurgical coal segment was $10 million for the three months ended June 30, 2011 compared to $6 million for the three months ended June 30, 2010. The increase in the low volatile metallurgical coal provision expense was attributable to the total Company increased long-term liability expense discussed in the total Company results of operations section. The per unit impairment was offset, in part, by additional tons sold in the period-to-period comparison. Also, low volatile metallurgical coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison which contributed to lower costs per ton sold.

Selling, administrative and other costs attributable to the low volatile metallurgical coal segment include selling, general and administrative expenses, direct administrative costs and water treatment expenses generated from the reverse osmosis plant. Selling, general and administrative expenses, excluding commission expense and water treatment expense, are allocated to various segments 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. Selling, administrative and other costs related to the low volatile metallurgical coal segment were $6 million for the three months ended June 30, 2011 compared to $5 million for the three months ended June 30, 2010. The cost increase attributable to the low volatile metallurgical coal segment is attributable to higher total Company selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Also, a reverse osmosis plant was completed and placed into service near the Buchanan Mine. Active mine water discharge is being treated by this facility and the costs of the services are charged to the mine based on gallons of water treated. Currently, the Buchanan Mine is the only facility using the plant. Construction of the plant was completed and the plant was placed into service earlier in 2011. Although the dollars related to the low volatile metallurgical coal segment increased, the additional tons sold increased at a greater proportion resulting in lower average unit cost per ton sold for selling, administrative and other costs.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $9 million for the three months ended June 30, 2011 compared to $5 million for the three months ended June 30, 2010. The increase was primarily due to additional equipment, infrastructure, and the reverse osmosis plant placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for low volatile metallurgical coal mines related to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. The increases in unit costs per ton sold were offset, in part, by additional low volatile metallurgical tons sold which lowered the unit cost per ton impact.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $189 million for the three months ended June 30, 2011 compared to a loss before income tax of $99 million for the three months ended June 30, 2010. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal division but not allocated to each individual mine.

Other coal segment produced coal sales include revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for both the three months ended June 30, 2011 and 2010. 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 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 $27 million for the three months ended June 30, 2011 compared to $1 million for the three months ended June 30, 2010. The increase was primarily due to purchasing additional tons of third party coal in the 2011 period due to a railroad bridge outage in order to meet contractual deliveries during this outage.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset in freight expense. Freight revenue was $59 million for the three months ended June 30, 2011 compared to $28 million for the three months ended June 30, 2010. The increase in freight revenue was primarily due to the 1.3 million ton increase in export tons in the period-to-period comparison.

Miscellaneous other income was $14 million for the three months ended June 30, 2011 compared to $16 million for the three months ended June 30, 2010. The decrease of $2 million was related to various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $296 million for the three months ended June 30, 2011 compared to $148 million for the three months ended June 30, 2010. The increase of $148 million was due to the following items:



	For the three months ended June 30,
	2011		2010		Variance
Abandonment of long-lived assets	$	115	$	—	$	115
Freight expense	59		28		31
Purchased coal	34		3		31
Coal contract buyout	5		—		5
Litigation expense	—		15		(15		)
Closed and idle mine cost	32		56		(24		)
Other	51		46		5
Total other coal segment costs	$	296	$	148	$	148


•	Abandonment of long-lived assets were $115 million for the three months ended June 30, 2011 as a result of the decision to permanently idle Mine 84.

•

Freight expense 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 expense is offset in freight revenue. Freight expense increased $31 million primarily due to the 1.3 million ton increase in export tons in the period-to-period comparison.


•	Purchased coal costs increased approximately $31 million in the period-to-period comparison primarily due to differences in the quality of coal purchased and an increase in volumes of coal purchased in order to fulfill various contracts during a railroad bridge outage that occurred in the 2011 period.


•	Coal contract buyout costs increased $5 million as a result of a lower priced coal sales contract being bought out in order to sell the tons on a higher priced contract in a future period.

•

Litigation expense of $15 million was recognized for the three months ended June 30, 2010 related to a settlement 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, of which $10 million was expensed in the first quarter of 2010 and $15 million was expensed in the second quarter of 2010.

•

Closed and idle mine costs decreased approximately $24 million for the three months ended June 30, 2011 compared to the three months ended June 30, 2010. The decrease was the result of a $28 million increase in the Fola reclamation liability in the 2010 period as a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans. Also, closed and idle mine costs increased $4 million due to the results of the annual engineering survey adjustments and other changes in the operational status of various other mines, between idled and operating, throughout both periods, none of which were individually material.


•	Other expenses related to the coal segment were $5 million higher for the three months ended June 30, 2011 compared to the three months ended June 30, 2010. These increases were related to various transactions that occurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 :

The gas segment contributed $28 million to earnings before income tax for the three months ended June 30, 2011 compared to $54 million for the three months ended June 30, 2010 .



	For the Three Months Ended												Difference to Three Months Ended
	June 30, 2011												June 30, 2010
	CBM		Conven- tional			Marcellus		Other Gas			Total Gas		CBM			Conven- tional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	115	$	42		$	28	$	4		$	189	$	(33	)	$	12		$	18	$	1		$	(2	)
Related Party	1		—			—		—			1		—			—			—		—			—
Total Outside Sales	116		42			28		4			190		(33		)	12			18		1			(2		)
Gas Royalty Interest	—		—			—		16			16		—			—			—		2			2
Purchased Gas	—		—			—		1			1		—			—			—		(1		)	(1		)
Other Income	—		—			—		4			4		—			—			—		4			4
Total Revenue and Other Income	116		42			28		25			211		(33		)	12			18		6			3
Lifting	12		14			4		1			31		—			10			3		—			13
Gathering	24		5			4		2			35		(1		)	2			2		2			5
General & Administration	15		8			5		—			28		—			3			4		—			7
Depreciation, Depletion and Amortization	25		16			8		3			52		(1		)	2			2		—			3
Gas Royalty Interest	—		—			—		14			14		—			—			—		2			2
Purchased Gas	—		—			—		2			2		—			—			—		—			—
Exploration and Other Costs	—		—			—		1			1		—			—			—		(4		)	(4		)
Other Corporate Expenses	—		—			—		18			18		—			—			—		(1		)	(1		)
Interest Expense	—		—			—		2			2		—			—			—		—			—
Total Cost	76		43			21		43			183		(2		)	17			11		(1		)	25
Earnings Before Noncontrolling Interest and Income Tax	40		(1		)	7		(18		)	28		(31		)	(5		)	7		7			(22		)
Noncontrolling Interest	—		—			—		—			—		—			—			—		4			4
Earnings Before Income Tax	$	40	$	(1	)	$	7	$	(18	)	$	28	$	(31	)	$	(5	)	$	7	$	3		$	(26	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $40 million to the total Company earnings before income tax for the three months ended June 30, 2011 compared to $71 million for the three months ended June 30, 2010 .



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)	22.9		22.8		0.1			0.4	%
Average CBM sales price per thousand cubic feet sold	$	5.12	$	6.57	$	(1.45	)	(22.1	)%
Average CBM lifting costs per thousand cubic feet sold	$	0.56	$	0.55	$	0.01		1.8	%
Average CBM gathering costs per thousand cubic feet sold	$	1.06	$	1.07	$	(0.01	)	(0.9	)%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.67	$	0.67	$	—		—	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.11	$	1.17	$	(0.06	)	(5.1	)%
Total Average CBM costs per thousand cubic feet sold	$	3.40	$	3.46	$	(0.06	)	(1.7	)%
Average Margin for CBM	$	1.72	$	3.11	$	(1.39	)	(44.7	)%

CBM sales revenues were $116 million for the three months ended June 30, 2011 compared to $149 million for the three months ended June 30, 2010 . The $33 million decrease was primarily due to a 22.1% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 0.4% increase in average volumes sold. The decrease in CBM average sales price is the result of various gas swap transactions maturing in each period. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 16.8 billion cubic feet of our produced CBM gas sales volumes for the three months ended June 30, 2011 at an average price of $5.26 per thousand cubic feet. In the three months ended June 30, 2010, these financial hedges represented 13.6 billion cubic feet at an average price of $8.15 per thousand cubic feet. CBM sales volumes increased 0.1 billion cubic feet primarily due to additional wells coming on-line from our on-going drilling program.

Total costs for the CBM segment were $76 million for the three months ended June 30, 2011 compared to $78 million for the three months ended June 30, 2010 . Lower costs in the period-to-period comparison were primarily related to lower unit costs offset, in part, by increased volumes sold.

CBM lifting costs were $12 million in both the three months ended June 30, 2011 and 2010 . Higher average CBM lifting unit costs were related to increased repairs of surface equipment and increased road maintenance costs, offset, in part, by improved salt water disposal costs due to re-utilizing water produced for hydraulic fracing.

CBM gathering costs were $24 million for the three months ended June 30, 2011 compared to $25 million for the three months ended June 30, 2010 . Lower average CBM gathering unit costs were related to lower fuel surcharges in the period-to-period comparison.

General and administrative costs attributable to the total gas division were $28 million for the three months ended June 30, 2011 compared to $21 million for the three months ended June 30, 2010 . The $7 million increase was attributable to additional corporate service charges from CONSOL Energy and additional staffing. The corporate service charge allocations are primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. The additional staffing was primarily due to the operational support personnel who were retained in connection with the Dominion Acquisition that occurred on April 30, 2010 as well as other additional support staffing requirements.

General and administrative costs for the CBM segment were $15 million for both the three months ended June 30, 2011 and June 30, 2010 . 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. Unit costs remained consistent in the period-to-period comparison.

Depreciation, depletion and amortization attributable to the CBM segment was $25 million for the three months ended June 30, 2011 compared to $26 million for the three months ended June 30, 2010. There was approximately $18 million, or $0.79 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 for the three months ended June 30, 2011. The production portion of depreciation, depletion and amortization was $21 million, or $0.90 per unit-of-production for the three months ended June 30, 2010. The CBM unit-of-production rate decreased due to revised rates which are generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. There was approximately $7 million, or $0.32 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 three months ended June 30, 2011. The non-production related depreciation, depletion and amortization was $5 million, or $0.27 per thousand cubic feet for the three months ended June 30, 2010. The increase was related to additional gathering assets placed in service after the 2010 period.

CONVENTIONAL GAS SEGMENT

The conventional segment had a loss before income tax of $1 million in the three months ended June 30, 2011 compared to $4 million of earnings before income tax in the three months ended June 30, 2010.



	For the Three Months Ended June 30,
	2011			2010		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)	8.0			6.4		1.6			25.0	%
Average Conventional sales price per thousand cubic feet sold	$	5.27		$	4.71	$	0.56		11.9	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.70		$	0.71	$	0.99		139.4	%
Average Conventional gathering costs per thousand cubic feet sold	$	0.66		$	0.44	$	0.22		50.0	%
Average Conventional general & administrative costs per thousand cubic feet sold	$	1.02		$	0.69	$	0.33		47.8	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.95		$	2.39	$	(0.44	)	(18.4	)%
Total Average Conventional costs per thousand cubic feet sold	$	5.33		$	4.23	$	1.10		26.0	%
Average Margin for Conventional	$	(0.06	)	$	0.48	$	(0.54	)	(112.5	)%

Conventional sales revenues were $42 million for the three months ended June 30, 2011 compared to $30 million for the three months ended June 30, 2010. The $12 million increase was primarily due to the 25.0% increase in volumes sold as well as an 11.9% increase in average sales price. Conventional sales volumes increased 1.6 billion cubic feet for the three months ended June 30, 2011 compared to the 2010 period primarily due to the Dominion Acquisition, which closed on April 30, 2010, as well as additional wells coming on-line. Approximately 95% of the acquired producing wells were conventional type wells. Average sales price increased primarily due to increased general market prices of natural gas and oil in the period-to-period comparison. The increase in conventional sales price was also the result of various gas swap transactions that matured in the three months ended June 30, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 4.0 billion cubic feet of our produced conventional gas sales volumes for the three months ended June 30, 2011 at an average price of $4.99 per thousand cubic feet. There were no conventional gas swap transactions that occurred in the three months ended June 30, 2010.

Total costs for the conventional segment were $43 million for the three months ended June 30, 2011 compared to $26 million for the three months ended June 30, 2010. The increase is attributable to increased variable costs associated with the additional volumes and higher average unit costs.

Conventional lifting costs were $14 million for the three months ended June 30, 2011 compared to $4 million for the three months ended June 30, 2010. The increase in lifting costs in the period-to-period comparison was primarily due to the timing of the Dominion Acquisition which only affected two months of operating results in the 2010 period. Lifting costs per unit increased primarily due to the higher cost structure of the conventional wells acquired.

Conventional gathering costs were $5 million for the three months ended June 30, 2011 compared to $3 million for the three months ended June 30, 2010. Gathering costs per unit increased primarily due to increased pipeline maintenance costs, increased compressor rentals and increased firm transportation charges.

General and administrative costs related to the Conventional gas segment were $8 million for the three months ended June 30, 2011 compared to $5 million for the three months ended June 30, 2010. 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 increases which were discussed in the CBM segment, combined with the increased volumes sold contributed to the increased general and administrative costs allocated to the conventional gas segment.

Depreciation, depletion and amortization costs were $16 million for the three months ended June 30, 2011 compared to $14 million for the three months ended June 30, 2010. There was approximately $14 million, or $1.71 per unit-of production, of depreciation, depletion and amortization related to conventional gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2011. There was approximately $13 million, or $2.18 per unit-of-production, of depreciation, depletion and amortization related to conventional gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2010. 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. The decrease in the unit-of-production rate is primarily the result of various acquisition adjustments that were reflected after the 2010 period. There was approximately $2 million, or $0.24 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2011. There was $1 million, or $0.21 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2010. The increase is related to various acquisition adjustments and additional infrastructure and equipment placed in service after the 2010 period.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $7 million to the total Company earnings before income tax for the three months ended June 30, 2011 . The Marcellus segment did not significantly contribute to earnings before income tax for the three months ended June 30, 2010.



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)	6.0		2.3		3.7			160.9	%
Average Marcellus sales price per thousand cubic feet sold	$	4.58	$	4.52	$	0.06		1.3	%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.66	$	0.64	$	0.02		3.1	%
Average Marcellus gathering costs per thousand cubic feet sold	$	0.71	$	1.05	$	(0.34	)	(32.4	)%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.74	$	0.59	$	0.15		25.4	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.39	$	2.12	$	(0.73	)	(34.4	)%
Total Average Marcellus costs per thousand cubic feet sold	$	3.50	$	4.40	$	(0.90	)	(20.5	)%
Average Margin for Marcellus	$	1.08	$	0.12	$	0.96		800.0	%

The Marcellus segment sales revenues were $28 million for the three months ended June 30, 2011 compared to $10 million for the three months ended June 30, 2010. The increase in Marcellus average sales price was the result of the improvement in general market prices combined with various gas swap transactions that matured in the three months ended June 30, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 2.2 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended June 30, 2011 at an average price of $4.53 per thousand cubic feet. There were no Marcellus gas swap transactions that occurred in the three months ended June 30, 2010. The increased sales volumes are primarily due to additional wells coming on-line from our on-going drilling program. At June 30, 2011, there were 74 Marcellus Shale wells in production. At June 30, 2010, there were 43 Marcellus Shale wells in production, including 17 wells acquired in connection with the Dominion Acquisition.

Marcellus lifting costs were $4 million for the three months ended June 30, 2011 compared to $1 million for the three months ended June 30, 2010. Lifting costs per unit increased $0.02 per thousand cubic feet sold due to increased fishing services and mechanical scale removal completed to improve well performance, increased activity on non-operated wells, increased idle rig charges as a result of an unutilized rig in the 2011 period and additional well tending costs as a result of an increased number of wells and an escalation in rates. These improvements were partially offset by lower salt water disposition costs due to re-utilizing water produced for hydraulic fracing and improved repairs and maintenance primarily the result of increased sales volumes.

Marcellus gathering costs were $4 million for the three months ended June 30, 2011 compared to $2 million for the three months ended June 30, 2010. Average gathering costs decreased $0.34 per unit primarily due to the 3.7 billion cubic feet of additional volumes sold.

General and administrative costs on the Marcellus gas segment were $5 million for the three months ended June 30, 2011 compared to $1 million for the three months ended June 30, 2010. General and administrative costs attributable to the total gas division are allocated to the individual gas segments based on a combination of production and employee counts. The total general and administrative costs increases which were discussed in the CBM segment combined with higher volumes of Marcellus gas sold contributed to the increase. General and administrative costs were $0.74 per thousand cubic feet sold for the three months ended June 30, 2011 compared to $0.59 per thousand cubic feet sold for the three months ended June 30, 2010.

Depreciation, depletion and amortization costs were $8 million for the three months ended June 30, 2011 compared to $6 million for the three months ended June 30, 2010. There was approximately $7 million, or $1.18 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 for the three months ended June 30, 2011. There was approximately $5 million, or $1.96 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 for the three months ended June 30, 2010. 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 $0.21 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis in the three months ended June 30, 2011. There was less than $1 million, or $0.16 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis in the three months ended June 30, 2010. The increase is related to additional infrastructure and equipment placed in service after the 2010 period.

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 $4 million for the three months ended June 30, 2011 and $3 million for the three months ended June 30, 2010. Total costs related to these other sales were $6 million in the 2011 period and were $4 million in the 2010 period. The increase in costs in the period-to-period comparison was primarily attributable to additional gathering costs attributable to the increase in volumes sold. 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. Royalty interest gas sales revenue was $16 million for the three months ended June 30, 2011 compared to $14 million for the three months ended June 30, 2010. 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.



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.0		3.4		0.6			17.6	%
Average Sales Price Per thousand cubic feet	$	4.08	$	4.20	$	(0.12	)	(2.9	)%

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 $1 million for the three months ended June 30, 2011 compared to $2 million for the three months ended June 30, 2010.



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.3		0.3		—			—	%
Average Sales Price Per thousand cubic feet	$	4.61	$	5.69	$	(1.08	)	(19.0	)%

Other income was $4 million for the three months ended June 30, 2011 and was not significant for the three months ended June 30, 2010. The increase was primarily due to gains on dispositions of non-core acreage and various other 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. Royalty interest gas costs were $14 million for the three months ended June 30, 2011 compared to $12 million for the three months ended June 30, 2010. 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.



	For the Three Months Ended June 30,
	2011		2010		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.0		3.4		0.6		17.6	%
Average Cost Per thousand cubic feet sold	$	3.61	$	3.42	$	0.19	5.6	%

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 lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $2 million in both the three months ended June 30, 2011 and 2010.



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.4		0.3		0.1			33.3	%
Average Cost Per thousand cubic feet sold	$	4.37	$	4.55	$	(0.18	)	(4.0	)%

Exploration and other costs were $1 million for the three months ended June 30, 2011 compared to $5 million for the three months ended June 30, 2010. The $4 million decrease in costs is primarily related to a favorable settlement involving defective pipe which was recognized in the 2011 period that reduced expense and various exploration transactions that occurred throughout both periods, none of which were individually material. Costs included in the exploration and other cost line are detailed as follows:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Dry hole and lease expiration costs (including settlement)	$	—	$	3	$	(3	)	(100.0	)%
Exploration	1		2		(1		)	(50.0	)%
Total Exploration and Other Costs	$	1	$	5	$	(4	)	(80.0	)%

Other corporate expenses were $18 million for the three months ended June 30, 2011 compared to $19 million for the three months ended June 30, 2010. The $1 million decrease in the period-to-period comparison was made up of the following items:



	For the Three Months Ended June 30,
	2011		2010		Variance			Percent Change
Variable interest earnings	$	—	$	4	$	(4	)	(100.0	)%
Legal fees	—		3		(3		)	(100.0	)%
Unutilized firm transportation	4		—		4			100.0	%
Short-term incentive compensation	8		8		—			—	%
Stock-based compensation	4		3		1			33.3	%
Bank fees	2		1		1			100.0	%
Total Other Corporate Expenses	$	18	$	19	$	(1	)	(5.3	)%

•

Variable interest earnings were 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. Also, CONSOL Energy is the main customer of the third party, and based on our analysis, is the primary beneficiary. Therefore, the entity was fully consolidated and the earnings impact was fully reversed in the non-controlling interest line as discussed below.


•	Legal fees were related to expenses for the special committee formed during the CNX Gas take-in transaction that occurred in the 2010 period.


•	Unutilized firm transportation represents excess pipeline transportation capacity that the gas division obtained to enable gas production to flow uninterrupted as the gas operations continues to increase sales volumes.


•	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 costs. Short-term incentive compensation expense remained consistent in the period-to-period comparison.


•	Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas division. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.

Interest expense related to the gas segment remained consistent at $2 million for both the three months ended June 30, 2011 and 2010. Interest was incurred by the gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interest entity.

Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which CONSOL Energy holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas division 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 division. 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 June 30, 2011 compared to the three months ended June 30, 2010 :

The other segment includes activity from the 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 $82 million for the three months ended June 30, 2011 compared to a loss before income tax of $75 million for the three months ended June 30, 2010 . The other segment also included total company income tax expense of $21 million for the three months ended June 30, 2011 compared to $25 million for the three months ended June 30, 2010 .



	For the Three Months Ended June 30,
	2011			2010			Variance			Percent Change
Sales—Outside	$	85		$	72		$	13		18.1	%
Other Income	4			7			(3		)	(42.9	)%
Total Revenue	89			79			10			12.7	%
Cost of Goods Sold and Other Charges	101			84			17			20.2	%
Depreciation, Depletion & Amortization	5			4			1			25.0	%
Taxes Other Than Income Tax	3			3			—			—	%
Interest Expense	62			63			(1		)	(1.6	)%
Total Costs	171			154			17			11.0	%
Loss Before Income Tax	(82		)	(75		)	(7		)	(9.3	)%
Income Tax	21			25			(4		)	(16.0	)%
Net Loss	$	(103	)	$	(100	)	$	(3	)	(3.0	)%

Industrial supplies:

Total revenue from industrial supplies was $56 million for the three months ended June 30, 2011 compared to $46 million for the three months ended June 30, 2010 . The increase was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $56 million for the three months ended June 30, 2011 compared to $48 million for the three months ended June 30, 2010 . The increase of $8 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Total revenue from transportation operations was $32 million for the three months ended June 30, 2011 compared to $30 million for the three months ended June 30, 2010 . The increase of $2 million 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 $22 million for the three months ended June 30, 2011 compared to $20 million for the three months ended June 30, 2010 . The increase of $2 million was primarily related to the additional through-put tons handled by the operations.

Miscellaneous other:

Additional other income of $1 million was recognized for the three months ended June 30, 2011 compared to $3 million for the three months ended June 30, 2010 . The $2 million decrease was primarily due to the 2010 successful resolution of an outstanding tax issue with the Canadian Revenue Authority for the years 1997 through 2003 in which it was determined that CONSOL Energy was entitled to interest on a tax refund, lower equity in earnings of affiliates in the current period compared to the prior year period and various transactions that occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest expense, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $93 million for the three months ended June 30, 2011 compared to $86 million for the three months ended June 30, 2010 . Other corporate costs increased due to the following items:



	For the Three Months Ended June 30,
	2011		2010		Variance
Loss on extinguishment of debt	$	16	$	—	$	16
Evaluation fees for non-core asset dispositions	3		—		3
Bank fees	5		5		—
Acquisition and financing fees	—		14		(14		)
Interest expense	62		63		(1		)
Other	7		4		3
Total other corporate costs	$	93	$	86	$	7

• On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these Notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.

• Evaluation fees for non-core asset dispositions increased $3 million in the period-to-period comparison due to various corporate initiatives that began after the 2010 period.

• Bank fees remained consistent in the period-to-period comparison.

• Acquisition and financing fees of $14 million incurred in the three months ended June 30, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion. There were no acquisition and financing fees in the 2011 period.

• Interest expense decreased $1 million in the period-to-period comparison primarily due to lower borrowings on the revolving credit facility.

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

Income Taxes:

The effective income tax rate was 21.7% in the three months ended June 30, 2011 compared to 26.3% in the three months ended June 30, 2010 . The decrease in the effective tax rate in the three months ended June 30, 2011 as compared to the three months ended June 30, 2010 was attributable to the proportion of coal pre-tax earnings and gas pre-tax earnings to the total pre-tax earnings. The relationship between pre-tax earnings and percentage depletion also impacts the effective tax rate. The effective income tax rate was also impacted by several discrete transactions that occurred in the three months ended June 30, 2011. See Note 5—Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Three Months Ended June 30,
	2011			2010			Variance			Percent Change
Total Company Earnings Before Income Tax	$	99		$	96		$	3		3.1	%
Income Tax Expense	$	21		$	25		$	(4	)	(16.0	)%
Effective Income Tax Rate	21.7		%	26.3		%	(4.6		)%

Results of Operations

Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $270 million, or $1.18 per diluted share, for the six months ended June 30, 2011 . Net income attributable to CONSOL Energy shareholders was $167 million, or $0.81 per diluted share, for the six months ended June 30, 2010 .

The coal division includes steam coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $451 million of earnings before income tax for the six months ended June 30, 2011 compared to $231 million for the six months ended June 30, 2010 . The total coal division sold 32.7 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, for the six months ended June 30, 2011 compared to 30.8 million tons for the six months ended June 30, 2010 .

The average sales price and total costs per ton for all active coal operations were as follows:



	For the Six Months Ended June 30,
	2011		2010		Variance		Percent Change
Average Sales Price per ton sold	$	70.62	$	60.27	$	10.35	17.2	%
Average Costs per ton sold	49.35		46.16		3.19		6.9	%
Margin	$	21.27	$	14.11	$	7.16	50.7	%

The higher average sales price per ton sold reflects successful renegotiation of several domestic steam contracts whose pricing took effect January 1, 2011, another strong quarter of high volatile metallurgical coal sales and continued demand for our premium low volatile metallurgical coal. Also, 6.0 million tons were sold on the export market at an average sales price of $118.20 for the six months ended June 30, 2011 compared to 4.1 million tons at an average price of $91.25 per ton for the six months ended June 30, 2010.

Average costs per ton sold increased in the period-to-period comparison due primarily to higher operating supplies and maintenance costs per ton sold due to additional maintenance and equipment overhaul costs, additional roof control costs, higher costs associated with the increased sales price of coal sold, such as royalties and production related taxes, increased depreciation, depletion and amortization due to additional assets placed into service after the 2010 period, and increased OPEB and salary pension expense as discussed below.

The total gas division includes coalbed methane (CBM), conventional, Marcellus and other gas. The total gas division contributed $52 million of earnings before income tax for the six months ended June 30, 2011 compared to $128 million for the six months ended June 30, 2010 . Total gas production was 73.4 billion cubic feet for the six months ended June 30, 2011 compared to 55.9 billion cubic feet for the six months ended June 30, 2010 .

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



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	5.00	$	6.55	$	(1.55	)	(23.7	)%
Average Costs per thousand cubic feet sold	3.82		3.75		0.07			1.9	%
Margin	$	1.18	$	2.80	$	(1.62	)	(57.9	)%

Total gas division outside sales revenues were $367 million for the six months ended June 30, 2011 compared to $366 million for the six months ended June 30, 2010 . The increase was primarily due to the 31.3% increase in volumes sold, offset, in part, by the 23.7% reduction in average price per thousand cubic feet sold. The decrease in average sales price is the result of various gas swap transactions that occurred throughout both periods and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial

hedges represented approximately 36.1 billion cubic feet of our produced gas sales volumes for the six months ended June 30, 2011 at an average price of $5.29 per thousand cubic feet. These financial hedges represented 26.6 billion cubic feet of our produced gas sales volumes for the six months ended June 30, 2010 at an average price of $8.45 per thousand cubic feet.

Total gas unit costs increased slightly for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 primarily due to the impact of the higher cost structure of the producing wells purchased in the Dominion Acquisition. The purchased Dominion wells increased total operating costs by $0.68 per thousand cubic feet due to higher costs and lower volumes produced related to the age of these wells compared to the legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.61 per thousand cubic feet primarily due to the additional volumes produced and improved depreciation, depletion and amortization. Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition, which occurred on April 20, 2010. Lower depreciation, depletion and amortization rates were the result of the higher proportion of gas reserves compared to capital placed in service as of December 31, 2010.

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.



	For the Six Months Ended June 30,
	2011		2010		Variance		Percent Change
Employee wages and related expenses	$	39	$	33	$	6	18.2	%
Advertising and promotion	5		1		4		400.0	%
Demurrage charges	4		1		3		300.0	%
Commissions	8		7		1		14.3	%
Consulting and professional services	13		13		—		—	%
Miscellaneous	15		14		1		7.1	%
Total Company Selling, General and Administrative Expenses	$	84	$	69	$	15	21.7	%

Total Company selling, general and administrative expenses increased due to the following:


•	Employee wages and related expenses increased $6 million which was primarily attributable to the support staff retained in the Dominion Acquisition and additional hiring of support staff in the period-to-period comparison.


•	Advertising and promotion expense increased $4 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.


•	Demurrage charges increased $3 million due to additional export business by CONSOL Energy and other suppliers causing higher vessel traffic at the exporting facilities. The additional vessel traffic caused vessels to wait in the harbors for more days in the period-to-period comparison, resulting in additional expense.


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


•	Consulting and professional services remained consistent in the period-to-period comparison.


•	Miscellaneous selling, general and administrative expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Total Company long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial liabilities was $167 million for the six months ended June 30, 2011 compared to $146 million for the six months ended June 30, 2010. The increase of $21 million was due primarily to a revision to the OPEB and salary pension expense. The additional OPEB and salary pension expense related to employees retiring sooner than originally anticipated and average claim costs being higher than originally anticipated. Also, higher provision expenses in the period-to-period comparison were due to changes in the discount rates used at the measurement date, which is December 31. See Note 3—Components of Pension 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 Notes to the Condensed Consolidated Financial Statements for additional detail of total Company expense increases.

TOTAL COAL SEGMENT ANALYSIS for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 :

The coal segment contributed $451 million of earnings before income tax in the six months ended June 30, 2011 compared to $231 million in the six months ended June 30, 2010 . Variances by the individual coal segments are discussed below.



	For the Six Months Ended											Difference to Six Months Ended
	June 30, 2011											June 30, 2010
	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	$	1,583	$	196	$	516	$	14		$	2,309	$	121		$	83	$	240	$	10		$	454
Purchased Coal	—		—		—		33			33		—			—		—		9			9
Total Outside Sales	1,583		196		516		47			2,342		121			83		240		19			463
Freight Revenue	—		—		—		96			96		—			—		—		37			37
Other Income	3		6		—		28			37		(1		)	3		—		3			5
Total Revenue and Other Income	1,586		202		516		171			2,475		120			86		240		59			505
Costs and Expenses:
Total operating costs	951		83		142		123			1,299		32			40		30		(2		)	100
Total provisions	111		9		19		33			172		13			4		6		(42		)	(19		)
Total administrative & other costs	84		8		13		46			151		11			5		4		1			21
Depreciation, depletion and amortization	151		15		18		122			306		23			9		9		105			146
Total Costs and Expenses	1,297		115		192		324			1,928		79			58		49		62			248
Freight Expense	—		—		—		96			96		—			—		—		37			37
Total Costs	1,297		115		192		420			2,024		79			58		49		99			285
Earnings (Loss) Before Income Taxes	$	289	$	87	$	324	$	(249	)	$	451	$	41		$	28	$	191	$	(40	)	$	220

STEAM COAL SEGMENT

The steam coal segment contributed $289 million to total Company earnings before income tax for the six months ended June 30, 2011 compared to $248 million for the six months ended June 30, 2010 . The steam coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2011		2010		Variance		Percent Change
Produced Steam Tons Sold (in millions)	27.2		27.0		0.2		0.7	%
Average Sales Price Per Steam Ton Sold	$	58.30	$	54.12	$	4.18	7.7	%
Average Operating Costs Per Steam Ton Sold	$	35.05	$	34.00	$	1.05	3.1	%
Average Provision Costs Per Steam Ton Sold	$	4.08	$	3.62	$	0.46	12.7	%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	3.10	$	2.72	$	0.38	14.0	%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	5.55	$	4.75	$	0.80	16.8	%
Total Average Costs Per Steam Ton Sold	$	47.78	$	45.09	$	2.69	6.0	%
Margin Per Steam Ton Sold	$	10.52	$	9.03	$	1.49	16.5	%

Steam coal revenue was $1,583 million for the six months ended June 30, 2011 compared to $1,462 million for the six months ended June 30, 2010. The $121 million increase was attributable to a $4.18 per ton higher average sales prices and 0.2 million higher tons sold. The higher average steam coal sales price in the 2011 period was the result of a successful renegotiation of several domestic steam contracts whose pricing took effect on January 1, 2011. Also, 1.2 million tons of steam coal was sold on the export market at an average sales price of $67.53 per ton for the six months ended June 30, 2011 compared to 1.0 million tons at an average price of $59.75 per ton for the six months ended June 30, 2010. The steam coal segment was also impacted by 2.5 million tons of steam coal sold on the high volatile metallurgical coal market for the six months ended June 30, 2011, which increased 1.0 million tons compared to the six months ended June 30, 2010.

Operating costs are comprised 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 $951 million for the six months ended June 30, 2011 compared to $919 million for the six months ended June 30, 2010. Operating costs related to the steam coal segment increased primarily due to higher average costs per ton sold as well as higher volumes sold.

Changes in the average operating costs per ton for steam coal sold were primarily related to the following items:


•	Average preparation costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.

•

Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, to improve the safety of our mines and to provide a more reliable source of production for our customers.


•	Production taxes average cost per ton sold increased primarily due to the $4.18 per ton higher average sales price.

•

Labor and related benefits were impaired slightly on a cost per ton sold basis due to higher costs, offset, in part by additional volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Additional employees in the period-to-period comparison also contributed to higher labor costs. Non-union benefit rates for active employees also increased as a result of continued increases in healthcare costs. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to

be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover the benefits.


•	Contract mining fees were lower due to fewer contractors being retained to mine our reserves in the period-to-period comparison.


•	Average operating costs per steam ton sold decreased due to higher tons sold. Fixed costs were allocated over more tons; therefore, unit cost decreased.

Provision costs 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, and 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 are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. The average provision costs attributable to the steam coal segment were $111 million for the six months ended June 30, 2011 compared to $98 million for the six months ended June 30, 2010. The increased steam coal provision expense was attributable to the total Company increase in long-term liability expense discussed in the total Company results of operations section. Steam coal accretion expense related to mine closing and related liabilities increased approximately $1 million due to the results of the annual engineering survey adjustments and due to various changes in the related liability, none of which were individually material. These increases were offset, in part, by higher steam coal tons sold.

Selling, administrative and other costs attributable to the steam coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to various segments 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. Selling, administrative and other costs related to the steam coal segment were $84 million for the six months ended June 30, 2011 compared to $73 million for the six months ended June 30, 2010. The cost increases attributable to the steam coal segment were attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due to additional safety reward expense in the period-to-period comparison. These higher costs, offset by additional sales volumes, resulted in a $0.38 per ton increase in average cost per ton sold.

Depreciation, depletion and amortization for the steam coal segment was $151 million for the six months ended June 30, 2011 compared to $128 million for the six months ended June 30, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for steam coal mines due to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. These higher expenses, offset in part with additional sales tons, resulted in an $0.80 increase in average costs per ton sold.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $87 million to total Company earnings before income tax for the six months ended June 30, 2011 compared to $59 million for the six months ended June 30, 2010. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced High Vol Met Tons Sold (in millions)	2.5		1.5		1.0			66.7	%
Average Sales Price Per High Vol Met Ton Sold	$	77.37	$	75.52	$	1.85		2.4	%
Average Operating Costs Per High Vol Met Ton Sold	$	32.37	$	28.63	$	3.74		13.1	%
Average Provision Costs Per High Vol Met Ton Sold	$	3.68	$	3.15	$	0.53		16.8	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	3.33	$	2.34	$	0.99		42.3	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	5.86	$	4.13	$	1.73		41.9	%
Total Average Costs Per High Vol Met Ton Sold	$	45.24	$	38.25	$	6.99		18.3	%
Margin Per High Vol Met Ton Sold	$	32.13	$	37.27	$	(5.14	)	(13.8	%)

High volatile metallurgical coal revenue was $196 million for the six months ended June 30, 2011 compared to $113 million for the six months ended June 30, 2010. Strength in the metallurgical coal market has continued to allow the export of Northern Appalachian coal, historically sold domestically on the steam coal market, to crossover to the Brazilian and Asian metallurgical coal markets. Average sales prices for high volatile metallurgical coal increased due to growing the base of end user customers.

Operating costs related to the high volatile metallurgical coal segment were $83 million for the six months ended June 30, 2011 compared to $43 million for the six months ended June 30, 2010. Operating costs related to the high volatile metallurgical coal segment increased primarily due to higher average costs per ton sold and higher volumes sold.

Changes in average operating costs per ton for high volatile metallurgical coal sold were primarily related to the following items:

•

Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher labor and related costs were also due to higher non-union benefit rates for active employees related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Increased labor and related benefit costs per unit sold were also offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.


•	Average coal preparation costs per ton sold increased due to additional maintenance projects that have been completed at our preparation plants in the period-to-period comparison.


•	Production taxes average cost per ton sold increased due to the $1.85 per ton higher average sales price.


•	Average operating costs per ton sold decreased due to higher tons sold. Fixed costs were allocated over more tons; therefore, unit costs decreased.

The provision expense attributable to the high volatile metallurgical coal segment was $9 million for the six months ended June 30, 2011 compared to $5 million for the six months ended June 30, 2010. The increase in the high volatile metallurgical coal provision expense was attributable to the total Company increased long-term liability expense discussed in the total Company results of operations section. The per unit impairment was offset, in part, by additional tons sold in the period-to-period comparison. Also, high volatile metallurgical coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison which contributed to lower costs per ton sold.

Selling, administrative and other costs attributable to the high volatile metallurgical coal segment include selling, general and administrative expenses and direct administrative costs. Selling, general and administrative expenses, excluding commission expense, are allocated to various segments 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. Selling, administrative and other costs related to the high volatile metallurgical coal segment were $8 million for the six months ended June 30, 2011 compared to $3 million for the six months ended June 30, 2010. The cost increase attributable to the high volatile metallurgical coal segment is attributable to higher total Company selling, general and administrative expenses as discussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs are primarily due to additional safety reward expense in the period-to-period comparison. These increases in expense increased costs per ton sold and were offset, in part, by higher volumes of high volatile metallurgical coal sold.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $15 million for the six months ended June 30, 2011 compared to $6 million for the six months ended June 30, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for high volatile metallurgical coal mines related to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. These increases in unit costs per ton sold were offset, in part, by additional high volatile metallurgical tons sold which lowered the unit cost per ton impact.

The high volatile metallurgical coal segment 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 volatile metallurgical coal segment contributed $324 million to total Company earnings before income tax in the six months ended June 30, 2011 compared to $133 million in the six months ended June 30, 2010. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Six Months Ended June 30,
	2011		2010		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)	2.8		2.2		0.6		27.3	%
Average Sales Price Per Low Vol Met Ton Sold	$	183.71	$	125.47	$	58.24	46.4	%
Average Operating Costs Per Low Vol Met Ton Sold	$	50.63	$	50.30	$	0.33	0.7	%
Average Provision Costs Per Low Vol Met Ton Sold	$	6.59	$	6.11	$	0.48	7.9	%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	4.79	$	4.17	$	0.62	14.9	%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	6.32	$	4.17	$	2.15	51.6	%
Total Average Costs Per Low Vol Met Ton Sold	$	68.33	$	64.75	$	3.58	5.5	%
Margin Per Low Vol Met Ton Sold	$	115.38	$	60.72	$	54.66	90.0	%

Low volatile metallurgical coal revenue was $516 million for the six months ended June 30, 2011 compared to $276 million for the six months ended June 30, 2010. The $240 million increase was attributable to a $58.24 per ton higher average sales price due to the continued strengthening of the low volatile metallurgical market, both domestic and foreign. The continued strength of these markets is related to continued worldwide demand for premium low volatile metallurgical coal. For the 2011 period, 2.3 million tons of low volatile metallurgical coal was sold on the export market at an average price of $187.88 per ton compared to 1.7 million tons at an average price of $122.66 per ton for the 2010 period.

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 volatile metallurgical coal segment were $142 million for the six months ended June 30, 2011 compared to $112 million for the six months ended June 30, 2010. Operating costs related to the low volatile metallurgical coal segment increased primarily due to higher volumes sold, offset, in part, by lower average operating costs per ton sold.

Changes in the average operating costs per ton for low volatile metallurgical coal sold were primarily related to the following items:

•

Average operating supplies and maintenance costs per ton sold increased due to additional roof control costs, additional ventilation of coalbed methane gas and additional equipment overhaul costs. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of support put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period.


•	Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.

•

Coal inventory volumes increased 0.1 million tons at June 30, 2011 compared to December 31, 2010 and carrying value increased $3.58 per ton in the corresponding period. Coal inventory decreased 0.2 million tons at June 30, 2010 compared to December 31, 2009 and the carrying value of the inventory during the corresponding period increased $8.07 per ton. These changes in inventory caused a reduction in average operating cost per ton sold in the period-to-period comparison.


•	Labor and related benefits were improved on a cost per ton sold basis due to higher volumes sold. Labor and related benefit dollars spent were higher in the 2011 period compared to the 2010 period due to additional employees and increased non-union benefit rates for active employees which were related to the continued increase in healthcare costs.


•	Preparation plant and power average cost per ton sold were improved primarily due to higher tons sold.


•	Average operating costs per low volatile metallurgical tons sold decreased due to higher tons sold. Fixed costs are then spread over more tons, thereby decreasing unit costs.

The provision expense attributable to the low volatile metallurgical coal segment was $19 million for the six months ended June 30, 2011 compared to $13 million for the six months ended June 30, 2010. The increased low volatile metallurgical coal provision expense per ton sold was attributable to the total Company's increased long-term liability expense discussed in the total Company results of operations section, offset, in part, by higher volumes of low volatile metallurgical coal sold. Low volatile metallurgical coal accretion expense related to mine closing and related liabilities decreased approximately $1 million in the period-to-period comparison as a result of the annual engineering surveys which contributed to lower average costs per ton sold.

Selling, administrative and other costs attributable to the low volatile metallurgical coal segment include selling, general and administrative expenses, direct administrative costs and water treatment expenses generated from the reverse osmosis plant. Selling, general and administrative costs, excluding commission expense and water treatment expense, are allocated to various segments 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. Selling, administrative and other costs related to the low volatile metallurgical coal segment were $13 million for the six months ended June 30, 2011 compared to $9 million for the six months ended June 30, 2010. The cost increase related to the low volatile metallurgical coal segment was attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section. Also, a reverse osmosis plant was completed and placed into service near the Buchanan Mine. Active mine water discharge is being treated by

this facility and the costs of these services are charged to the mine based on gallons of water treated. Currently, the Buchanan Mine is the only facility using the plant. Construction of the plant was completed and the plant was placed into service in the six months ended June 30, 2011. These increases in expense were offset, in part, by higher volumes of low volatile metallurgical coal sold.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $18 million for the six months ended June 30, 2011 compared to $9 million for the six months ended June 30, 2010. The increase was primarily due to additional equipment, infrastructure and the reverse osmosis plant placed into service after the 2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates due to additional air shafts being placed into service after the 2010 period which had a higher unit rate than historical shafts put into service. These increases in average costs per ton sold were offset, in part, by higher low volatile metallurgical tons sold which lowered the unit cost per ton impact.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $249 million for the six months ended June 30, 2011 compared to a loss before income tax of $209 million for the six months ended June 30, 2010. 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 includes revenue from the sale of 0.2 million tons of coal which was recovered during the reclamation process at idled facilities for the six months ended June 30, 2011 and 0.1 million tons for the six months ended June 30, 2010. 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 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 $33 million for the six months ended June 30, 2011 compared to $24 million for the six months ended June 30, 2010. The increase was primarily due to increased volumes sold.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset in freight expense. Freight revenue was $96 million for the six months ended June 30, 2011 compared to $59 million for the six months ended June 30, 2010. The increase in freight revenue was primarily due to the 2.0 million ton increase in export tons in the period-to-period comparison.

Miscellaneous other income was $28 million for the six months ended June 30, 2011 compared to $25 million for the six months ended June 30, 2010. The increase of $3 million was related to various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $420 million for the six months ended June 30, 2011 compared to $321 million for the six months ended June 30, 2010. The increase of $99 million was due to the following items:



	For the six months ended June 30,
	2011		2010		Variance
Abandonment of long-lived asset	$	115	$	—	$	115
Freight expense	96		59		37
Purchased Coal	47		27		20
Coal contract buyout	5		—		5
Closed and idle mines	59		113		(54		)
Litigation expense	—		35		(35		)
Other	98		87		11
Total other coal segment costs	$	420	$	321	$	99


•	Abandonment of long-lived assets were $115 million for the six months ended June 30, 2011 as a result of the decision to permanently idle Mine 84.

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset in freight revenue. The increase was primarily due to the 2.0 million ton increase in export tons in the period-to-period comparison.


•	Purchased coal costs increased approximately $20 million in the period-to-period comparison primarily due to differences in the quality of coal purchased and an increase in the volumes of coal purchased in the period-to-period comparison.


•	Coal contract buyout costs increased $5 million as a result of a lower priced coal sales contract being bought out in order to sell the tons on a higher priced contract in a future period.

•

Closed and idle mine costs decreased approximately $54 million in the six months ended June 30, 2011 compared to the six months ended June 30, 2010. In the 2010 period, 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 was increased $54 million.

•

Litigation expense of $25 million was recognized for the six months ended June 30, 2010 related to an anticipated legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized for the six months ended June 30, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million.

•

Other expenses related to the coal segment were $11 million higher for the six months ended June 30, 2011 compared to the six months ended June 30, 2010. The increase was related to a $5 million charge for an additional liability due to Pennsylvania stream remediation and $6 million of the increase was related to various transactions that occurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 :

The gas segment contributed $52 million to earnings before income tax in the six months ended June 30, 2011 compared to $128 million in the six months ended June 30, 2010 .



	For the Six Months Ended												Difference to Six Months Ended
	June 30, 2011												June 30, 2010
	CBM		Conven- tional			Marcellus		Other Gas			Total Gas		CBM			Conven- tional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	229	$	81		$	48	$	7		$	365	$	(80	)	$	48		$	30	$	3		$	1
Related Party	2		—			—		—			2		—			—			—		—			—
Total Outside Sales	231		81			48		7			367		(80		)	48			30		3			1
Gas Royalty Interest	—		—			—		35			35		—			—			—		7			7
Purchased Gas	—		—			—		2			2		—			—			—		(3		)	(3		)
Other Income	—		—			—		5			5		—			—			—		4			4
Total Revenue and Other Income	231		81			48		49			409		(80		)	48			30		11			9
Lifting	25		26			6		1			58		—			21			4		1			26
Gathering	47		12			7		2			68		(3		)	9			3		1			10
General & Administration	30		16			8		—			54		—			11			6		—			17
Depreciation, Depletion and Amortization	49		33			14		5			101		(5		)	17			6		2			20
Gas Royalty Interest	—		—			—		31			31		—			—			—		7			7
Purchased Gas	—		—			—		3			3		—			—			—		(1		)	(1		)
Exploration and Other Costs	—		—			—		4			4		—			—			—		(5		)	(5		)
Other Corporate Expenses	—		—			—		29			29		—			—			—		2			2
Interest Expense	—		—			—		5			5		—			—			—		1			1
Total Cost	151		87			35		80			353		(8		)	58			19		8			77
Earnings Before Noncontrolling Interest and Income Tax	80		(6		)	13		(31		)	56		(72		)	(10		)	11		3			(68		)
Noncontrolling Interest	—		—			—		4			4		—			—			—		8			8
Earnings Before Income Tax	$	80	$	(6	)	$	13	$	(35	)	$	52	$	(72	)	$	(10	)	$	11	$	(5	)	$	(76	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $80 million to the total Company earnings before income tax for the six months ended June 30, 2011 compared to $152 million for the six months ended June 30, 2010 .



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)	45.3		44.7		0.6			1.3	%
Average CBM sales price per thousand cubic feet sold	$	5.12	$	6.97	$	(1.85	)	(26.5	)%
Average CBM lifting costs per thousand cubic feet sold	$	0.56	$	0.56	$	—		—	%
Average CBM gathering costs per thousand cubic feet sold	$	1.04	$	1.11	$	(0.07	)	(6.3	)%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.67	$	0.69	$	(0.02	)	(2.9	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.09	$	1.21	$	(0.12	)	(9.9	)%
Total Average CBM costs per thousand cubic feet sold	$	3.36	$	3.57	$	(0.21	)	(5.9	)%
Average Margin for CBM	$	1.76	$	3.40	$	(1.64	)	(48.2	)%

CBM sales revenues were $231 million in the six months ended June 30, 2011 compared to $311 million for the six months ended June 30, 2010. The $80 million decrease was primarily due to a 26.5% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 1.3% increase in average volumes sold. The decrease in CBM average sales price is the result of various gas swap transactions that matured in each period and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 28.6 billion cubic feet of our produced CBM gas sales volumes for the six months ended June 30, 2011 at an average price of $5.26 per thousand cubic feet. For the six months ended June 30, 2010, these financial hedges represented 26.6 billion cubic feet at an average price of $8.45 per thousand cubic feet. CBM sales volumes increased 0.6 billion cubic feet primarily due to additional wells coming on-line from our on-going drilling program.

Total costs for the CBM segment were $151 million for the six months ended June 30, 2011 compared to $159 million for the six months ended June 30, 2010. Lower costs in the period-to-period comparison are primarily related to lower unit costs offset, in part, by increased volumes sold.

CBM lifting costs were $25 million for both the six months ended June 30, 2011 and June 30, 2010. Lifting costs remained consistent in the period-to-period comparison and the increased volumes sold did not significantly impact lifting costs per unit which remained consistent at $0.56 per thousand cubic feet sold.

CBM gathering costs were $47 million for the six months ended June 30, 2011 compared to $50 million for the six months ended June 30, 2010. Lower average CBM gathering unit costs are related to lower fuel surcharges, lower compressor maintenance and lower equipment lease expenses in the period-to-period comparison.

General and administrative costs attributable to the total gas division were $54 million for the six months ended June 30, 2011 compared to $37 million for the six months ended June 30, 2010. The $17 million increase was attributable to additional corporate service charges from CONSOL Energy and additional staffing. Corporate service charge allocations are primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. The additional staffing is primarily due to the Dominion Acquisition which closed on April 30, 2010 because the majority of the operational support personnel were retained.

General and administrative costs for the CBM segment were $30 million in both the six months ended June 30, 2011 and June 30, 2010. 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 consistent general and administrative costs attributable to the CBM segment coupled with higher volumes of CBM sold resulted in lower unit costs in the period-to-period comparison.

Depreciation, depletion and amortization attributable to the CBM segment was $49 million for the six months ended June 30, 2011 compared to $54 million for the six months ended June 30, 2010. There was approximately $35 million, or $0.79 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 six months ended June 30, 2011. The production portion of depreciation, depletion and amortization was $42 million, or $0.94 per unit-of-production in the six months ended June

30, 2010. The CBM unit-of-production rate decreased due to revised rates which were generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. There was approximately $14 million, or $0.30 average per unit cost of depreciation, depletion and amortization relating to gathering and other equipment reflected on a straight line basis for the six months ended June 30, 2011. The non-production related depreciation, depletion and amortization was $12 million, or $0.27 per thousand cubic feet for the six months ended June 30, 2010. The increase was related to additional gathering assets placed in service after the 2010 period.

CONVENTIONAL GAS SEGMENT

The conventional segment had a loss before income tax of $6 million for the six months ended June 30, 2011 compared to $4 million of earnings before income tax for the six months ended June 30, 2010.



	For the Six Months Ended June 30,
	2011			2010		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)	16.2			6.9		9.3			134.8	%
Average Conventional sales price per thousand cubic feet sold	$	5.01		$	4.78	$	0.23		4.8	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.59		$	0.78	$	0.81		103.8	%
Average Conventional gathering costs per thousand cubic feet sold	$	0.76		$	0.45	$	0.31		68.9	%
Average Conventional general & administrative costs per thousand cubic feet sold	$	0.99		$	0.67	$	0.32		47.8	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.03		$	2.39	$	(0.36	)	(15.1	)%
Total Average Conventional costs per thousand cubic feet sold	$	5.37		$	4.29	$	1.08		25.2	%
Average Margin for Conventional	$	(0.36	)	$	0.49	$	(0.85	)	(173.5	)%

Conventional sales revenues were $81 million for the six months ended June 30, 2011 compared to $33 million for the six months ended June 30, 2010. The $48 million increase was primarily due to the 134.8% increase in volumes sold as well as the 4.8% increase in average sales price. Conventional sales volumes increased 9.3 billion cubic feet in the six months ended June 30, 2011 compared to the 2010 period primarily due to the Dominion Acquisition, which closed on April 30, 2010. Approximately 95% of the acquired producing wells were conventional type wells. Average sales price increased primarily due to quality of natural gas and increased oil prices in the period-to-period comparison. The increase in conventional sales price was also the result of various gas swap transactions that matured in the six months ended June 30, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 4.0 billion cubic feet of our produced conventional gas sales volumes for the six months ended June 30, 2011 at an average price of $4.99 per thousand cubic feet. There were no conventional gas swap transactions that occurred in the six months ended June 30, 2010.

Total costs for the conventional segment were $87 million for the six months ended June 30, 2011 compared to $29 million for the six months ended June 30, 2010. The increase is attributable to increased variable costs associated with the additional sales volumes and higher 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.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $13 million to the total Company earnings before income tax for the six months ended June 30, 2011 compared to $2 million for the six months ended June 30, 2010 .



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)	10.7		3.7		7.0			189.2	%
Average Marcellus sales price per thousand cubic feet sold	$	4.48	$	4.91	$	(0.43	)	(8.8	)%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.54	$	0.53	$	0.01		1.9	%
Average Marcellus gathering costs per thousand cubic feet sold	$	0.66	$	1.11	$	(0.45	)	(40.5	)%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.72	$	0.62	$	0.10		16.1	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.35	$	2.02	$	(0.67	)	(33.2	)%
Total Average Marcellus costs per thousand cubic feet sold	$	3.27	$	4.28	$	(1.01	)	(23.6	)%
Average Margin for Marcellus	$	1.21	$	0.63	$	0.58		92.1	%

The Marcellus segment sales revenues were $48 million for the six months ended June 30, 2011 compared to $18 million for the six months ended June 30, 2010. The $30 million increase was primarily due to a 189.2% increase in average volumes sold, offset, in party, by a 8.8% decrease in average sales price per thousand cubic feet sold. The decrease in Marcellus average sales price was the result of the decline in general market prices. These decreases were offset, in part, by various gas swap transactions that matured in the six months ended June 30, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 3.5 billion cubic feet of our produced Marcellus gas sales volumes for the six months ended June 30, 2011 at an average price of $4.53 per thousand cubic feet. There were no Marcellus gas swap transactions that occurred in the six months ended June 30, 2010. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program. At June 30, 2011, there were 74 Marcellus Shale wells in production. At June 30, 2010, there were 43 Marcellus Shale wells in production, including 17 wells acquired in connection with the Dominion Acquisition.

Marcellus lifting costs were $6 million for the six months ended June 30, 2011 compared to $2 million for the six months ended June 30, 2010. Lifting costs per unit increased $0.01 per thousand cubic feet sold primarily due to increased expenses for fishing services and mechanical scale removal performed to improve production, increased non-operated well costs, and increased well tending due to an increased number of wells and escalation of rates. These improvements were partially offset by lower salt water disposition costs due to re-utilizing water produced for hydraulic fracing and improved repairs and maintenance primarily the result of increased sales volumes.

Marcellus gathering costs were $7 million for the six months ended June 30, 2011 compared to $4 million for the six months ended June 30, 2010. Average gathering costs decreased $0.45 per unit primarily due to the 7.0 billion cubic feet of additional volumes sold.

General and administrative costs on the Marcellus gas segment were $8 million for the six months ended June 30, 2011 compared to $2 million for the six months ended June 30, 2010. 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 increases which were discussed in the CBM segment and higher volumes of Marcellus gas sold contributed to the increase in the Marcellus gas segment. General and administrative costs were $0.72 per thousand cubic feet sold for the six months ended June 30, 2011 compared to $0.62 per thousand cubic feet sold for the six months ended June 30, 2010.

Depreciation, depletion and amortization costs were $14 million for the six months ended June 30, 2011 compared to $8 million for the six months ended June 30, 2010. There was approximately $12 million, or $1.11 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 six months ended June 30, 2011. There was approximately $7 million, or $1.86 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 for the six months ended June 30, 2010. The rate was 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 $2 million, or $0.24 per thousand cubic feet, of depreciation, depletion and amortization

related to gathering and other equipment that was reflected on a straight line basis for the six months ended June 30, 2011. There was $1 million, or $0.16 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the six months ended June 30, 2010. The increase was related to additional infrastructure and equipment placed in service after the 2010 period.

OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $7 million for the six months ended June 30, 2011 and $4 million for the six months ended June 30, 2010. Total costs related to these other sales were $8 million for the 2011 period and were $4 million for the 2010 period. The increase in costs in the period-to-period comparison were primarily attributable to depreciation, depletion and amortization and increased lifting and gathering costs. 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 2011. The increase in the rate was related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. Increased lifting costs were primarily attributable to increased non-operated shale wells in the period-to-period comparison. Increased gathering costs were attributable to the increased sales volumes. 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. Royalty interest gas sales revenue was $35 million for the six months ended June 30, 2011 compared to $28 million for the six months ended June 30, 2010. 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.



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	8.3		5.8		2.5			43.1	%
Average Sales Price Per thousand cubic feet	$	4.24	$	4.88	$	(0.64	)	(13.1	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $2 million for the six months ended June 30, 2011 compared to $5 million for the six months ended June 30, 2010.



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.5		0.8		(0.3		)	(37.5	)%
Average Sales Price Per thousand cubic feet	$	4.54	$	5.74	$	(1.20	)	(20.9	)%

Other income was $5 million for the six months ended June 30, 2011 compared to $1 million for the six months ended June 30, 2010. The $4 million increase was primarily due to increased earnings from equity affiliates, gains on dispositions of non-core acreage and various other 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. Royalty interest gas costs were $31 million for the six months ended June 30, 2011 compared to $24 million for the six months ended June 30, 2010. 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.



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	8.3		5.8		2.5			43.1	%
Average Cost Per thousand cubic feet sold	$	3.76	$	4.07	$	(0.31	)	(7.6	)%

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 lower 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 for the six months ended June 30, 2011 compared to $4 million for the six months ended June 30, 2010.



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.7		—			—	%
Average Cost Per thousand cubic feet sold	$	3.47	$	5.39	$	(1.92	)	(35.6	)%

Exploration and other costs were $4 million for the six months ended June 30, 2011 compared to $9 million for the six months ended June 30, 2010. The $5 million decrease in costs is primarily related to a favorable settlement involving defective pipe which reduced expense in the 2011 period and lower dry hole costs in the 2011 period compared to the 2010 period. Costs included in the exploration and other cost line are detailed as follows:



	For the Six Months Ended June 30,
	2011		2010		Variance			Percent Change
Dry Hole and Lease Expiration Costs (including settlement)	$	1	$	7	$	(6	)	(85.7	)%
Exploration	3		2		1			50.0	%
Total Exploration and Other Costs	$	4	$	9	$	(5	)	(55.6	)%

Other corporate expenses were $29 million for the six months ended June 30, 2011 compared to $27 million for the six months ended June 30, 2010. The $2 million increase in the period-to-period comparison was made up of the following items:



	For the Six Months Ended June 30,
	2011			2010		Variance			Percent Change
Unutilized firm transportation	$	6		$	—	$	6		100.0	%
Stock based compensation	9			7		2			28.6	%
Bank fees	3			1		2			200.0	%
Short-term incentive compensation	13			12		1			8.3	%
Variable interest earnings	(4		)	4		(8		)	(200.0	)%
Other	2			3		(1		)	(33.3	)%
Total Other Corporate Expenses	$	29		$	27	$	2		7.4	%


•	Unutilized firm transportation represents pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continues to increase sales volumes.


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


•	Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.


•	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 costs. Short-term incentive compensation expense was higher for the 2011 period compared to the 2010 period due to the projected higher payouts related to the periods presented.


•	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. Also, CONSOL Energy is the main customer of the third party, and based on analysis, is the primary beneficiary. Therefore, the entity is fully consolidated and the earnings impact is fully reversed in the non-controlling interest line discussed below.


•	Other corporate related expense decreased $1 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 $5 million for the six months ended June 30, 2011 compared to $4 million for the six months ended June 30, 2010. Interest was incurred by the gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interest entity. The $1 million increase was primarily due to higher levels of borrowings on the revolving credit facility 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 CONSOL Energy 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 six months ended June 30, 2011 compared to the six months ended June 30, 2010 :

The other segment includes activity from the 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 $153 million for the six months ended June 30, 2011 compared to a loss before income tax of $120 million for the six months ended June 30, 2010 . The other segment also includes total company income tax expense of $80 million for the six months ended June 30, 2011 compared to $60 million for the six months ended June 30, 2010 .



	For the Six Months Ended June 30,
	2011			2010			Variance			Percent Change
Sales—Outside	$	164		$	145		$	19		13.1	%
Other Income	7			17			(10		)	(58.8	)%
Total Revenue	171			162			9			5.6	%
Cost of Goods Sold and Other Charges	183			198			(15		)	(7.6	)%
Depreciation, Depletion & Amortization	9			9			—			—	%
Taxes Other Than Income Tax	6			6			—			—	%
Interest Expense	126			69			57			82.6	%
Total Costs	324			282			42			14.9	%
Loss Before Income Tax	(153		)	(120		)	(33		)	(27.5	)%
Income Tax	80			60			20			33.3	%
Net Loss	$	(233	)	$	(180	)	$	(53	)	(29.4	)%

Industrial supplies:

Total revenue from industrial supplies was $110 million for the six months ended June 30, 2011 compared to $97 million for the six months ended June 30, 2010 . The increase was related to higher sales volumes.

Total costs related to industrial supply sales were $113 million for the six months ended June 30, 2011 compared to $98 million for the six months ended June 30, 2010 . The increase of $15 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Total revenue from transportation operations was $59 million for the six months ended June 30, 2011 compared to $54 million for the six months ended June 30, 2010 . The increase of $5 million 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 $44 million for the six months ended June 30, 2011 compared to $39 million for the six months ended June 30, 2010 . The increase of $5 million was related to the additional through-put tons handled by the operations.

Miscellaneous other:

Additional other income of $2 million was recognized for the six months ended June 30, 2011 compared to $11 million for the six months ended June 30, 2010 . The $9 million decrease was primarily due to the 2010 successful resolution of an outstanding tax issue with the Canadian Revenue Authority for the years 1997 through 2003 in which CONSOL Energy was entitled to interest on a tax refund, lower equity in earnings of affiliates in the current period compared to the prior year period and various transactions that have occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest expense, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $167 million for the six months ended June 30, 2011 compared to $145 million for the six months ended June 30, 2010 . Other corporate costs increased due to the following items:



	For the Six Months Ended June 30,
	2011		2010		Variance
Interest expense	$	126	$	69	$	57
Loss on extinguishment of debt	16		—		16
Bank fees	11		7		4
Evaluation fees for non-core asset dispositions	3		—		3
Acquisition and financing fees	—		61		(61		)
Other	11		8		3
	$	167	$	145	$	22


•	Interest expense increased $57 million primarily related to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition.

•

On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.


•	Bank fees increased $4 million primarily due to the bank facility being amended and extended on April 12, 2011.


•	Evaluation fees for non-core asset dispositions increased $3 million in the period-to-period comparison due to various corporate initiatives that began after the 2010 period.


•	Acquisition and financing fees of $61 million incurred in the three months ended June 30, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion. There were no acquisition and financing fees in the 2011 period.


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

Income Taxes:

The effective income tax rate was 23.0% for the six months ended June 30, 2011 compared to 25.0% for the six months ended June 30, 2010 . The decrease in the effective tax rate for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 was attributable to the proportion of coal pre-tax earnings and gas pre-tax earnings to the total pre-tax earnings. The relationship between percentage depletion and pre-tax earnings also impacts the effective tax rate. See Note 5—Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Six Months Ended June 30,
	2011			2010			Variance			Percent Change
Total Company Earnings Before Income Tax	$	350		$	238		$	112		47.1	%
Income Tax Expense	$	80		$	60		$	20		33.3	%
Effective Income Tax Rate	23.0		%	25.0		%	(2.0		)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On April 12, 2011, CONSOL Energy amended and extended its $1.5 billion Senior Secured Credit Agreement through April 12, 2016. The previous facility was set to expire on May 7, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1.5 billion for borrowings and letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. 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 2.50 to 1.00, 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 4.90 to 1.00 at June 30, 2011 . 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 2.42 to 1.00 at June 30, 2011 . The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, 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. The senior secured leverage ratio was 0.21 to 1.00 at June 30, 2011 . 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 company and amend, modify or restate, in any material way, the senior unsecured notes. At June 30, 2011 , the facility had no outstanding borrowings and $ 267 million of letters of credit outstanding, leaving $ 1.233 billion 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 also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $200 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. 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 financial institutions. At June 30, 2011 , eligible accounts receivable totaled approximately $200 million and there were outstanding borrowings of $70 million against the facility. There were no letters of credit outstanding against the facility at June 30, 2011 .

On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% Notes due March 1, 2012 in accordance with the terms of the indenture governing the Notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. CONSOL Energy's loss on extinguishment of debt was $16 million, which primarily represents the interest that would have been paid on these notes if held to maturity.

On April 12, 2011, CNX Gas entered into a $1.0 billion Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the $700 million senior secured credit facility which was set to expire on May 6, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0 billion for borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. The facility was established to meet the asset development needs of the company. 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 and its subsidiaries. The interest coverage ratio was 44.69 to 1.00 at June 30, 2011 . 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 and its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas and 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 1.15 to 1.00 at June 30, 2011 . Covenants in the facility limit our ability to dispose of assets, make investments, pay dividends and merge with another company. At June 30, 2011 , the facility had approximately $ 261 million drawn and $ 70 million of letters of credit outstanding, leaving $ 669 million of unused capacity.

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 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 its working capital requirements, to service its debt obligations, to fund planned capital expenditures or to 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 hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $71 million at June 30, 2011 . The ineffective portion of these contracts was insignificant to earnings in the three and six months ended June 30, 2011 . No issues related to our hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Six Months Ended June 30,
	2011			2010			Change
Cash flows from operating activities	$	795		$	506		$	289
Cash used in investing activities	$	(574	)	$	(5,037	)	$	4,463
Cash (used in) provided by financing activities	$	(228	)	$	4,500		$	(4,728	)

Cash flows provided by operating activities changed in the period-to-period comparison primarily due to the following items:

•

Operating cash flow increased in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-period comparison. The 2011 net income included approximately $75 million of a reduction due to the abandonment of Mine 84 which is discussed further in Note 8—Property, Plant and Equipment, in the Consolidated Financial Statements included in this Form 10-Q. This reduction did not have a corresponding reduction to cash flows from operating activities because it was primarily related to the write-down of assets remaining at Mine 84 at the time of the abandonment, not a cash obligation.


•	Operating cash flows increased due to various changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years, none of which were individually material.


•	Operating cash flows increased due to income taxes paid of $81 million in the six months ended June 30, 2011 compared to $107 million in the six months ended June 30, 2010. Income tax payments vary from period-to-period based on many factors, including methodologies employed to maximize benefits to the Company and expected annual taxable income levels at the time payments are owed.

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


•	On April 30, 2010, CONSOL Energy paid $3.476 billion for the Dominion Acquisition. See Note 2—Acquisitions and Dispositions, in the Consolidated Financial Statements included in this Form 10-Q for additional details.


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

•

Total capital expenditures increased $7 million to $585 million in the six months ended June 30, 2011 compared to $578 million in the six months ended June 30, 2010. Capital expenditures for the gas segment increased $130 million due to the additional drilling in the period-to-period comparison. The increased gas segment capital was primarily due to the increased Marcellus Shale drilling. Capital expenditures for coal and other activities decreased $123 million in the period-to-period comparison. Face extension projects at various locations were lower by $67 million as a result of the majority of these projects being completed during the 2010 period, $13 million was incurred in the 2010 period as a result of a longwall shield lease buyout, the 2011 period was lower by approximately $21 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011, and a $63 million reduction related to airshafts and equipment expenditures throughout both periods. These reductions in coal and other capital were offset, in part by an approximate $41 million increase in expenditures related primarily to the ongoing development of the BMX Mine which is scheduled to go on-line in 2014.

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


•	Proceeds of $2.75 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.


•	In 2010, proceeds of $1.83 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.


•	In 2011, CONSOL Energy repaid $130 million of borrowings under the accounts receivable securitization facility. In 2010, CONSOL Energy received proceeds of $150 million under this facility.


•	In 2011, CONSOL Energy paid $266 million, including a make-whole provision, to redeem the 7.875% notes that were due in March 2012.


•	In 2011, CONSOL Energy paid outstanding borrowings of $155 million under the revolving credit facility. In 2010, CONSOL Energy paid $123 million under this facility.


•	Dividends of $45 million were paid in 2011 compared to $41 million in 2010. The increase was due to the 44.3 million additional shares issued on March 31, 2010.


•	In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior unsecured notes due in March 2021.


•	In 2011, CNX Gas, a wholly-owned subsidiary, received $132 million of proceeds from its revolving credit facility compared to receiving $9 million in 2010.

The following is a summary of our significant contractual obligations at June 30, 2011 (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	$	260,750	$	—	$	—	$	—	$	260,750
Borrowings Under Securitization Facility	70,000		—		—		—		70,000
Purchase Order Firm Commitments	172,233		154,246		10,964		—		337,443
Gas Firm Transportation	44,141		72,498		61,459		294,978		473,076
Long-Term Debt	16,743		9,144		5,173		3,111,744		3,142,804
Interest on Long-Term Debt	245,609		491,081		492,191		677,688		1,906,569
Capital (Finance) Lease Obligations	8,540		13,574		10,130		32,482		64,726
Interest on Capital (Finance) Lease Obligations	4,345		7,111		5,568		6,872		23,896
Operating Lease Obligations	85,003		135,563		94,947		127,332		442,845
Long-Term Liabilities—Employee Related (a)	228,292		480,679		515,531		2,442,865		3,667,367
Other Long-Term Liabilities (b)	335,524		145,220		72,802		412,386		965,932
Total Contractual Obligations (c)	$	1,471,180	$	1,509,116	$	1,268,765	$	7,106,347	$	11,355,408

_________________________


(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. 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 2011 contributions are expected to approximate $ 71.7 million.


(b)	Other long-term liabilities include mine reclamation and closure and other long-term liability costs.


(c)	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 June 30, 2011 , CONSOL Energy had total long-term debt of $3.208 billion outstanding, including the current portion of long-term debt of $25 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 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 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 $ 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. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.


•	$ 32 million in advance royalty commitments with an average interest rate of 7.56 % per annum.


•	An aggregate principal amount of $8 million on a variable rate note due in December 2012 that bears interest at 4.28 % at June 30, 2011 . 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 6.46 % per annum.

At June 30, 2011 , CONSOL Energy also had no outstanding borrowings and had approximately $ 267 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At June 30, 2011 , CONSOL Energy had $70 million of borrowings under the accounts receivable securitization facility.

At June 30, 2011 , CNX Gas, a wholly owned subsidiary, had $ 261 million of aggregate principal amounts of outstanding borrowings and approximately $ 70 million of letters of credit outstanding under its $1.0 billion secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $ 3.2 billion at June 30, 2011 and $ 2.9 billion at December 31, 2010 . Total equity increased primarily due to net income attributable to CONSOL Energy shareholders, proceeds received under the Patient Protection and Affordable Care Act, and amortization of stock-based compensation awards. Approximately $7.8 million of proceeds were received under the Patient Protection and Affordable Care Act related to reimbursements from the Federal government for retiree health spending which are reflected in Other Comprehensive Income. There is no guarantee that additional proceeds will be received under this program. These increases were offset, in part, by the declaration of dividends, changes in the value of cash flow hedges and the issuance of treasury stock. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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



Declaration Date	Amount Per Share		Record Date	Payment Date
July 29, 2011	$	0.10	August 10, 2011	August 22, 2011
April 29, 2011	$	0.10	May 13, 2011	May 24, 2011
January 28, 2011	$	0.10	February 8, 2011	February 18, 2011

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 2.42 to 1.00 and our availability was approximately $ 1.2 billion at June 30, 2011 . The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the six months ended June 30, 2011 .

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 financial 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 June 30, 2011 . The various multi-employer benefit plans are discussed in Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2010 Form 10-K. 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 June 30, 2011 . Management believes these items will expire without being funded. See Note 11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

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:


•	deterioration in economic conditions in any of the industries 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;


•	our customers extending existing contracts or entering into new long-term contracts for coal;


•	our reliance on major customers;


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


•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our coal and gas to market;


•	a loss of our competitive position because of the competitive nature of the coal and gas industries, or a loss of our

competitive position because of overcapacity in these industries impairing our profitability;


•	our ability to negotiate a new agreement with the United Mine Workers' of America and 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 emissions;


•	the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for coal and natural gas, as well as the impact of any adopted regulations on our coal mining operations due to the venting of coalbed methane which occurs during mining;


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


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


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


•	decreases in the availability of, or increases in, the price of commodities and services used in our mining and gas operations, as well as our exposure under “take or pay” contracts we entered into with well service providers to obtain services of which if not used could impact our cost of production;


•	obtaining and renewing governmental permits and approvals for our coal and gas operations;


•	the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our coal and gas operations;


•	the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine or well;


•	the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal and gas operations;


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


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


•	costs associated with perfecting title for coal or gas rights on some of our properties;


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


•	the impacts of various asbestos litigation claims;


•	increased exposure to employee related long-term liabilities;


•	increased exposure to multi-employer pension plan 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 exceeding total service and interest cost in a plan year;


•	acquisitions that we recently have completed 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 and divestitures we anticipate may not occur or produce anticipated proceeds;


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


•	increased exposure on our financial performance due to the degree we are leveraged;


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


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


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


•	other factors discussed in our 2010 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 commodity 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. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty, 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 our risk assessment procedures and internal controls, mitigates our exposure to material risks. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy's results of operations depending on market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CONSOL Energy's 2010 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at June 30, 2011 . A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $46.7 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $46.7 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2011 , CONSOL Energy had $3,208 million aggregate principal amount of debt outstanding under fixed-rate instruments and $331 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 no borrowings outstanding at June 30, 2011 . CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 4.09% per annum during the six months ended June 30, 2011 . 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. 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 $ 261 million at June 30, 2011 and bore interest at a weighted average rate of 2.19% per annum during the six months ended June 30, 2011 . Due to the level of borrowings against this facility and the low weighted average interest rate in the three months ended June 30, 2011 , 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.

Hedging Volumes

As of July 13, 2011 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
2011 Fixed Price Volumes
Hedged Mcf	13,035,790		23,069,925		23,948,795		23,948,795		84,003,305
Weighted Average Hedge Price/Mcf	$	5.56	$	5.14	$	5.12	$	5.18	$	5.21
2012 Fixed Price Volumes
Hedged Mcf	14,529,077		14,529,077		14,688,738		14,688,738		58,435,630
Weighted Average Hedge Price/Mcf	$	5.52	$	5.52	$	5.52	$	5.52	$	5.52
2013 Fixed Price Volumes
Hedged Mcf	8,167,370		8,258,119		8,348,868		8,348,868		33,123,225
Weighted Average Hedge Price/Mcf	$	5.21	$	5.21	$	5.21	$	5.21	$	5.21
2014 Fixed Price Volumes
Hedged Mcf	7,284,883		7,365,826		7,446,770		7,446,770		29,544,249
Weighted Average Hedge Price/Mcf	$	5.43	$	5.43	$	5.43	$	5.43	$	5.43


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 June 30, 2011 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 includes 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 in the Company's internal controls over financial reporting 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.

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 (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 June 30, 2011 , 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) or (ii) 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. There was one Mine Act section 107(a) imminent danger orders to immediately remove miners. There was one pending legal action before the Federal Mine Safety and Health Review Commission (excluding actions pending before Administrative Law Judges). There were no fatalities during the three months ended June 30, 2011 .

During the six months ended June 30, 2011 , 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) or (ii) 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. There were two Mine Act section 107(a) imminent danger orders to immediately remove miners. There was one pending legal action before the Federal Mine Safety and Health Review Commission (excluding actions pending before Administrative Law Judges). There were no fatalities during the six months ended June 30, 2011 .

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 June 30, 2011 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)
Amvest - Fola Complex	14	—	—	$	45	14
Bailey	10	—	—	$	165	13
Blacksville #2	51	—	2	$	101	7
Buchanan	36	—	—	$	113	24
Enlow Fork	15	—	—	$	14	7
Loveridge	76	1	1	$	107	8
McElroy	70	—	2	$	152	21
Miller Creek Complex	28	—	—	$	20	5
Robinson Run	36	—	—	$	139	19
Shoemaker	45	—	1	$	151	10
Other (Keystone Plant)	—	—	—	$	5	—

__________________________


(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 received one Mine Act section 104 Significant & Substantial citations in the three months ended June 30, 2011 . Total proposed assessments were $6 in the three months ending June 30, 2011 . There were 11 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of June 30, 2011 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 June 30, 2011 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.

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 six months ended June 30, 2011 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)
Amvest - Fola Complex	31	—	1	$	62	14
Bailey	26	—	—	$	188	13
Blacksville #2	100	—	3	$	479	7
Buchanan	71	—	—	$	309	24
Enlow Fork	25	—	—	$	26	7
Loveridge	143	1	8	$	548	8
McElroy	145	—	3	$	436	21
Miller Creek Complex	54	—	—	$	42	5
Robinson Run	84	—	2	$	603	19
Shoemaker	105	—	2	$	345	10
Other (Keystone Plant)	1	—	—	$	5	—

__________________________


(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 received five Mine Act section 104 Significant & Substantial citations in the six months ended June 30, 2011 . Total proposed assessments were $34 in the six months ending June 30, 2011 . There were 11 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of June 30, 2011 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 six months ended June 30, 2011 for all alleged violations. The Company previously overstated the total dollar value of assessments at March 31, 2011 by $2.2 million. This column reflects the corrected amounts for the six months ending June 30, 2011. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7)


ITEM 6.	EXHIBITS



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 June 30, 2011 furnished in XBRL)

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

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: August 4, 2011



	CONSOL ENERGY INC.

	By:		/ S / J. B RETT H ARVEY
			J. Brett Harvey
			Chairman of the Board and Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)

	By:		/ S / W ILLIAM J. L YONS
			William J. Lyons
			Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial and Accounting Officer)

TABLE OF CONTENTS

Part I Item 1. Condensed Financial Statements Note 1 Basis Of Presentation:Note 2 Acquisitions and Dispositions:Note 3 Components Of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs:Note 4 Components Of Coal Workers Pneumoconiosis (cwp) and Workers Compensation Net Periodic Benefit Costs:Note 5 Income Taxes:Note 6 Inventories:Note 7 Accounts Receivable Securitization:Note 8 Property, Plant and Equipment:Note 9 Short-term Notes Payable:Note 10 Long-term Debt:Note 11 Commitments and Contingencies:Note 12 Derivative Instruments:Note 13 Other Comprehensive Loss:Note 14 Fair Value Of Financial Instruments:Note 15 Segment Information:Note 16 Guarantor Subsidiaries Financial Information:Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Item 1. Legal Proceedings Item 5. Other Information Item 6. Exhibits

CNX 10-Q Quarter ended June 30, 2011