Edgar Filing: CONSOL Energy Inc

Incremental Decrease
in Pre-tax Income
Assuming a
Hypothetical Price,
Exchange Rate or Interest
Rate Change of:

(in millions)

Natural Gas (a)

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

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

For the transition period from to

Commission file number: 001-14901

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)

Delaware

51-0337383

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

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

Yes x No ¨

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

Yes x No ¨

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

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

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

Yes ¨ No x

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


Class		Shares outstanding as of July 23, 2010
Common stock, $0.01 par value		225,794,229

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, 2010 and 2009	3
	Consolidated Balance Sheets at June 30, 2010 and December 31, 2009	4
	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2010	6
	Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	7
	Notes to Unaudited Consolidated Financial Statements	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	83

Item 4.	Controls and Procedures	84

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	86

Item 5.	Other Information	86

Item 6.	Exhibits	88

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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Sales—Outside	$	1,220,116		$	994,141		$	2,389,630		$	2,144,385
Sales—Gas Royalty Interests		14,151			8,666			28,490			21,298
Sales—Purchased Gas		1,740			1,166			4,756			2,631
Freight—Outside		28,075			27,087			59,275			58,003
Other Income		25,265			39,505			47,256			62,999

Total Revenue and Other Income		1,289,347			1,070,565			2,529,407			2,289,316
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		818,771			642,856			1,585,633			1,310,478
Acquisition and Financing Fees		17,515			—			64,078			—
Gas Royalty Interests Costs		11,528			6,458			23,725			17,049
Purchased Gas Costs		1,339			390			3,647			1,920
Freight Expense		28,075			27,087			59,275			58,003
Selling, General and Administrative Expenses		39,045			35,627			69,175			66,443
Depreciation, Depletion and Amortization		132,764			107,475			251,950			213,694
Interest Expense		65,038			6,945			73,183			15,457
Taxes Other Than Income		79,124			70,472			160,425			148,311

Total Costs		1,193,199			897,310			2,291,091			1,831,355

Earnings Before Income Taxes		96,148			173,255			238,316			457,961
Income Taxes		25,248			54,416			59,534			134,151

Net Income		70,900			118,839			178,782			323,810
Less: Net Income Attributable to Noncontrolling Interest		(4,232	)		(5,500	)		(11,845	)		(14,652	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	66,668		$	113,339		$	166,937		$	309,158

Earnings Per Share:
Basic	$	0.30		$	0.63		$	0.82		$	1.71

Dilutive	$	0.29		$	0.62		$	0.81		$	1.69

Weighted Average Number of Common Shares Outstanding:
Basic		225,715,539			180,644,498			203,842,526			180,610,676

Dilutive		228,081,103			183,073,413			206,311,383			182,833,111

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, 2010		December 31, 2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	34,313	$	65,607
Accounts and Notes Receivable:
Trade		245,796		317,460
Other Receivables		14,882		15,983
Accounts Receivable—Securitized		200,000		50,000
Inventories		293,850		307,597
Deferred Income Taxes		86,200		73,383
Recoverable Income Taxes		36,145		—
Prepaid Expenses		132,658		161,006

Total Current Assets		1,043,844		991,036
Property, Plant and Equipment:
Property, Plant and Equipment		14,589,592		10,681,955
Less—Accumulated Depreciation, Depletion and Amortization		4,667,316		4,557,665

Total Property, Plant and Equipment—Net		9,922,276		6,124,290
Other Assets:
Deferred Income Taxes		402,078		425,297
Investment in Affiliates		87,124		83,533
Other		232,769		151,245

Total Other Assets		721,971		660,075

TOTAL ASSETS	$	11,688,091	$	7,775,401

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)


	(Unaudited) June 30, 2010			December 31, 2009
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	265,089		$	269,560
Short-Term Notes Payable		358,550			472,850
Current Portion of Long-Term Debt		46,304			45,394
Accrued Income Taxes		—			27,944
Borrowings Under Securitization Facility		200,000			50,000
Other Accrued Liabilities		738,240			612,838

Total Current Liabilities		1,608,183			1,478,586
Long-Term Debt:
Long-Term Debt		3,111,079			363,729
Capital Lease Obligations		57,870			59,179

Total Long-Term Debt		3,168,949			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		2,688,122			2,679,346
Pneumoconiosis Benefits		187,285			184,965
Mine Closing		390,214			397,320
Gas Well Closing		113,825			85,992
Workers’ Compensation		156,420			152,486
Salary Retirement		165,127			189,697
Reclamation		51,902			27,105
Other		133,971			132,517

Total Deferred Credits and Other Liabilities		3,886,866			3,849,428

TOTAL LIABILITIES		8,663,998			5,750,922
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 225,754,286 Outstanding at June 30, 2010; 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009		2,273			1,830
Capital in Excess of Par Value		2,145,483			1,033,616
Preferred Stock, 15,000,000 authorized, None issued and outstanding		—			—
Retained Earnings		1,566,921			1,456,898
Accumulated Other Comprehensive Loss		(626,940	)		(640,504	)
Common Stock in Treasury, at Cost—1,535,140 Shares at June 30, 2010 and 1,928,159 Shares at December 31, 2009		(55,154	)		(66,292	)

Total CONSOL Energy Inc. Stockholders’ Equity		3,032,583			1,785,548
Noncontrolling Interest		(8,490	)		238,931

TOTAL EQUITY		3,024,093			2,024,479

TOTAL LIABILITIES AND EQUITY	$	11,688,091		$	7,775,401

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)


	Common Stock		Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2009	$	1,830	$	1,033,616		$	1,456,898		$	(640,504	)	$	(66,292	)	$	1,785,548		$	238,931		$	2,024,479

(Unaudited)
Net Income		—		—			166,937			—			—			166,937			11,845			178,782
Treasury Rate Lock (Net of $25 Tax)		—		—			—			(44	)		—			(44	)		—			(44	)
Gas Cash Flow Hedge (Net of $5,428 Tax)		—		—			—			(13,806	)		—			(13,806	)		5,252			(8,554	)
Actuarially Determined Long-Term Liability Adjustments (Net of $5,853 Tax)		—		—			—			9,388			—			9,388			5			9,393
Purchase of CNX Gas Noncontrolling Interest		—		—			—			18,026			—			18,026			(18,026	)		—

Comprehensive Income (Loss)		—		—			166,937			13,564			—			180,501			(924	)		179,577
Issuance of Treasury Stock		—		—			(16,220	)		—			11,138			(5,082	)		—			(5,082	)
Issuance of Common Stock		443		1,828,419			—			—			—			1,828,862			—			1,828,862
Issuance of CNX Gas Stock		—		—			—			—			—			—			2,178			2,178
Purchase of CNX Gas Noncontrolling Interest		—		(746,052	)		—			—			—			(746,052	)		(244,982	)		(991,034	)
Tax Benefit From Stock-Based Compensation		—		9,523			—			—			—			9,523			—			9,523
Stock-Based Compensation Awards to CNX Gas		—		2,126			—			—			—			2,126			(1,771	)		355
Amortization of Stock-Based Compensation Awards		—		17,851			—			—			—			17,851			2,198			20,049
Net Change in Crown Drilling Noncontrolling Interest		—		—			—			—			—			—			(4,120	)		(4,120	)
Dividends ($0.20 per share)		—		—			(40,694	)		—			—			(40,694	)		—			(40,694	)

Balance at June 30, 2010	$	2,273	$	2,145,483		$	1,566,921		$	(626,940	)	$	(55,154	)	$	3,032,583		$	(8,490	)	$	3,024,093

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,
	2010			2009
Operating Activities:
Net Income	$	178,782		$	323,810
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		251,950			213,694
Stock-Based Compensation		20,049			21,783
Gain on Sale of Assets		(866	)		(9,788	)
Amortization of Mineral Leases		3,981			2,398
Deferred Income Taxes		7,740			34,488
Equity in Earnings of Affiliates		(8,692	)		(6,800	)
Changes in Operating Assets:
Accounts and Notes Receivable		(76,977	)		100,554
Inventories		13,607			(96,845	)
Prepaid Expenses		4,712			18,505
Changes in Other Assets		19,475			5,347
Changes in Operating Liabilities:
Accounts Payable		25,409			(64,959	)
Other Operating Liabilities		64,643			45,117
Changes in Other Liabilities		(18,008	)		(30,977	)
Other		20,037			9,919

Net Cash Provided by Operating Activities		505,842			566,246

Investing Activities:
Capital Expenditures		(577,625	)		(496,419	)
Acquisition of Dominion Exploration and Production Business		(3,475,665	)		—
Purchase of CNX Gas Noncontrolling Interest		(991,034	)		—
Proceeds from Sales of Assets		2,487			48,184
Net Investment in Equity Affiliates		5,101			2,090

Net Cash Used in Investing Activities		(5,036,736	)		(446,145	)

Financing Activities:
Payments on Short-Term Borrowings		(114,300	)		(105,700	)
Payments on Miscellaneous Borrowings		(5,590	)		(9,282	)
Proceeds from Securitization Facility		150,000			—
Proceeds from Issuance of Long-Term Notes		2,750,000			—
Tax Benefit from Stock-Based Compensation		9,714			397
Dividends Paid		(40,694	)		(36,128	)
Proceeds from Issuance of Common Stock		1,828,862			—
Issuance of Treasury Stock		2,175			611
Debt Issuance and Financing Fees		(80,567	)		—
Noncontrolling Interest Member Distribution		—			(200	)

Net Cash Provided By (Used in) Financing Activities		4,499,600			(150,302	)
Net Decrease in Cash and Cash Equivalents		(31,294	)		(30,201	)
Cash and Cash Equivalents at Beginning of Period		65,607			138,512

Cash and Cash Equivalents at End of Period	$	34,313		$	108,311

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, 2010 are not necessarily indicative of the results that may be expected for future periods.

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

On March 31, 2010, CONSOL Energy issued 44,275,000 shares of common stock, which generated net proceeds of $1,828,862 to fund, in part, the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). The acquisition transaction closed April 30, 2010.

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


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2010	2009	2010	2009
Anti-Dilutive Options	822,749	1,659,105	822,749	1,659,695
Anti-Dilutive Restricted Stock Units	1,960	4,716	1,960	5,096
Anti-Dilutive Performance Stock Units	—	33,364	—	120,645

	824,709	1,697,185	824,709	1,785,436

Options exercised during the three months ended June 30, 2010 and 2009 were 62,813 shares and 38,413 shares, respectively. The weighted average exercise price per share of the options exercised during the three months ended June 30, 2010 and 2009 was $15.56 and $13.42, respectively. Additionally, during the three months ended June 30, 2010, and 2009, respectively, 28,395 and 25,668 fully vested restricted stock awards were released.

Options exercised during the six months ended June 30, 2010 and 2009 were 122,793 shares and 57,087 shares, respectively. The weighted average exercise price per share of the options exercised during the six months ended June 30, 2010 and 2009 was $18.02 and $11.69, respectively. Additionally, during the six months ended June 30, 2010, and 2009, respectively, 377,590 and 81,672 fully vested restricted stock awards were released.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Net income attributable to CONSOL Energy Inc. shareholders	$	66,668	$	113,339	$	166,937	$	309,158

Weighted average shares of common stock outstanding:
Basic		225,715,539		180,644,498		203,842,526		180,610,676
Effect of stock-based compensation awards		2,365,564		2,428,915		2,468,857		2,222,435

Dilutive		228,081,103		183,073,413		206,311,383		182,833,111

Earnings per share:
Basic	$	0.30	$	0.63	$	0.82	$	1.71

Dilutive	$	0.29	$	0.62	$	0.81	$	1.69

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

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

On April 30, 2010, CONSOL Energy completed the Dominion Acquisition for a cash payment of $3,474,198, which includes approximately $1,467 of unsettled post closing adjustments, which was principally allocated to oil and gas properties, wells and well related equipment. The acquisition, which was accounted for under the Business Combination Topic of the FASB Accounting Standards Codification, includes approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings are approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition is expected to enhance CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.

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


	Preliminary Estimates of Acquisition Date Fair Value
Assets
Current Assets:
Inventory	$	301
Prepaid Expenses		2,480

Total Current Assets		2,781
Property, plant and equipment		3,540,683
Total Assets	$	3,543,464

Liabilities
Current Liabilities:
Other Accrued Liabilities	$	10,114
Deferred Credits and Other Liabilities:
Gas Well Closing		55,248
Postretirement Benefits Other Than Pension		2,800
Salary Retirement		900
Other		204

Total Deferred Credits and Other Liabilities		59,152
Total Liabilities	$	69,266

Net Assets Acquired	$	3,474,198

The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of May 1, 2010. Net revenues and net income resulting from the Dominion Acquisition that were included in CONSOL Energy’s operating results were $33,395 and $618, respectively, for the three and six months ended June 30, 2010.

The unaudited pro forma results for the periods presented below are prepared as if the transaction occurred at the beginning of each period presented. Pro forma adjustments include estimated operating results, additional interest related to the bond issuance and 44,275,000 additional shares issued.


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2010	2009	2010	2009
Revenue	1,302,867	1,107,831	2,596,427	2,376,309
Earnings Before Taxes	94,080	110,823	184,904	332,318
Net Income	65,171	69,493	128,277	220,141
Basic Earnings Per Share	0.29	0.31	0.52	0.98
Dilutive Earnings Per Share	0.29	0.31	0.51	0.97

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

On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas outstanding common stock for a cash payment of $966,811 pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. All of the shares of CNX Gas that were not already owned by CONSOL Energy were acquired at a

price of $38.25 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 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/or proceeds from its recently closed offering of common stock.

In 2010, 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 months 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 as per the settlement referenced in “Note 11—Commitments and Contingencies.”

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

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

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 Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost	$	3,736		$	3,302		$	7,213		$	6,169		$	2,808		$	2,949		$	6,540		$	6,327
Interest cost		9,369			9,082			18,597			17,741			40,874			35,991			81,366			75,726
Expected return on plan assets		(9,206	)		(9,245	)		(18,524	)		(18,315	)		—			—			—			—
Amortization of prior service (credits)		(183	)		(277	)		(367	)		(554	)		(11,604	)		(11,604	)		(23,207	)		(23,207	)
Recognized net actuarial loss		8,070			5,692			15,935			11,131			17,674			10,209			35,072			25,178

Net periodic benefit cost	$	11,786		$	8,554		$	22,854		$	16,172		$	49,752		$	37,545		$	99,771		$	84,024

For the six months ended June 30, 2010, $32,340 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 approximately $72,000 to our pension trust in 2010.

CONSOL Energy does not expect to contribute to the other postemployment benefit plan in 2010. We intend to pay benefit claims as they become due. For the six months ended June 30, 2010, $76,555 of other postemployment benefits have been paid.

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

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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost	$	1,040		$	1,769		$	2,986		$	3,537		$	6,754		$	7,099		$	13,508		$	14,197
Interest cost		2,681			3,013			5,427			6,027			2,289			2,191			4,578			4,382
Amortization of actuarial gain		(5,777	)		(5,079	)		(10,758	)		(10,159	)		(768	)		(1,050	)		(1,536	)		(2,100	)
State administrative fees and insurance bond premiums		—			—			—			—			1,799			1,793			4,218			3,552
Legal and administrative costs		750			675			1,500			1,350			785			850			1,570			1,701

Net periodic cost (benefit)	$	(1,306	)	$	378		$	(845	)	$	755		$	10,859		$	10,883		$	22,338		$	21,732

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

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

CONSOL Energy does not expect to contribute to the CWP plan in 2010. We intend to pay benefit claims as they become due. For the six months ended June 30, 2010, $6,772 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2010. We intend to pay benefit claims as they become due. For the six months ended June 30, 2010, $18,929 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,
	2010					2009
	Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	83,411		35.0	%	$	160,286		35.0	%
Excess tax depletion		(30,186	)	(12.7	)		(38,927	)	(8.5	)
Effect of Domestic Production Activities Deduction		(3,293	)	(1.4	)		(7,327	)	(1.6	)
Net effect of state income taxes		8,009		3.4			18,318		4.0
Other		1,593		0.7			1,801		0.4

Income Tax Expense / Effective Rate	$	59,534		25.0	%	$	134,151		29.3	%

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

CONSOL Energy was advised by the Canadian Revenue Agency and various provinces that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Canadian tax returns filed for years 1997 through 2003 had been successfully resolved. As a result of the audit settlement, the Company reflected $3,450 as a discrete reduction to foreign income tax expense in the six months ended June 30, 2010. Accordingly, a discrete federal income tax expense of $1,457 was also recognized related to this transaction.

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

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

The total amounts of unrecognized tax benefits at June 30, 2010 and 2009 were $56,916 and $44,980, respectively. If these unrecognized tax benefits were recognized, approximately $15,502 and $14,657, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the six months ended June 30, 2010 and 2009.

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

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of June 30, 2010 and 2009, the Company reported an accrued interest liability relating to uncertain tax positions of $9,831 and $6,359, respectively. The accrued interest liability includes $1,493 and $438 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the six months ended June 30, 2010 and 2009, respectively.

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

NOTE 6—INVENTORIES:

Inventory components consist of the following:


	June 30, 2010		December 31, 2009
Coal	$	153,615	$	173,719
Merchandise for resale		44,614		44,842
Supplies		95,621		89,036

Total Inventories	$	293,850	$	307,597

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $18,847 and $13,696 at June 30, 2010 and December 31, 2009, respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

In April 2010, CONSOL Energy and certain of our U.S. subsidiaries amended their existing trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The amended facility allows CONSOL Energy to receive on a revolving basis up to $200,000, a $35,000 increase over the previous facility. The amended facility also allows for the issuance of letters of credit against the $200,000 capacity. At June 30, 2010, there were no letters of credit outstanding against the facility.

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

Effective January 1, 2010, CONSOL Energy modified the reporting of the Accounts Receivable securitization facility transactions in the Consolidated Financial Statements. The modification includes reporting

the pledge of collateral as Accounts Receivable—Securitized and the borrowings are now classified as debt in Borrowings under Securitization Facility. Additionally, similar reclassifications of prior period data have been made to conform to the six months ended June 30, 2010 classifications required by the Transfers and Servicing Topic of the FASB Accounting Standards Codification.

The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $553 and $1,005 for the three and six months ended June 30, 2010. Costs associated with the receivables facility totaled $833 and $1,768 for three and six months ended June 30, 2009. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.

At June 30, 2010 and December 31, 2009, eligible accounts receivable totaled $200,000 and $151,000, respectively. There was no subordinated retained interest at June 30, 2010. There was subordinated retained interest of $101,000 at December 31, 2009. Accounts Receivable—Securitization and Borrowings under Securitization Facility of $200,000 and $50,000 were recorded on the Consolidated Balance Sheet at June 30, 2010 and December 31, 2009, respectively. Also, the $150,000 increase in the accounts receivable securitization program for the six months ended June 30, 2010 is reflected in the net cash provided by financing activities in the Consolidated Statement of Cash Flows. There was no change in the facility usage in the six months ended June 30, 2009. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:

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


	June 30, 2010		December 31, 2009
Gas properties and related development	$	5,270,183	$	1,649,476
Coal & other plant and equipment		4,987,349		4,874,880
Coal properties and surface lands		1,312,097		1,284,795
Gas gathering equipment		898,737		804,212
Airshafts		638,627		622,068
Mine development		586,641		573,037
Leased coal lands		503,568		504,475
Coal advance mining royalties		389,631		366,312
Gas advance royalties		2,759		2,700

Total property, plant and equipment		14,589,592		10,681,955
Less Accumulated depreciation, depletion and amortization		4,667,316		4,557,665

Total Net Property, Plant and Equipment	$	9,922,276	$	6,124,290

NOTE 9—SHORT-TERM NOTES PAYABLE:

On May 7, 2010 CONSOL Energy entered into a four-year $1,500,000 senior secured credit facility, which extends through May 7, 2014. It replaced a five-year $1,000,000 senior secured credit facility which extended through June 2012. The new facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly.

The facility includes a minimum interest coverage ratio covenant of no less than 2.00 to 1.00, measured quarterly. The interest coverage ratio was 8.65 to 1.00 at June 30, 2010. The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The leverage ratio was 4.23 at June 30, 2010. The facility also includes a senior secured leverage ratio covenant of not more than 2.50 to 1.00, measured quarterly. The senior secured leverage ratio was 1.01 to 1.00 at June 30, 2010. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured or secured notes. At June 30, 2010, the $1,500,000 facility had $292,200 of borrowings outstanding and $267,985 of letters of credit outstanding, leaving $939,815 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 3.91% as of June 30, 2010.

CNX Gas has a four-year $700,000 senior secured credit agreement effective May 7, 2010, which extends through May 6, 2014. It replaced a five-year $200,000 unsecured credit agreement that extended through October 2010. The new facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. Effective June 30, 2010 the assets acquired in the Dominion Acquisition have been merged into one entity and the shares of this entity have been transferred to CNX Gas, making it a wholly-owned subsidiary of CNX Gas. The acquired assets are now pledged as collateral under the CNX Gas senior secured credit agreement. Collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.23 to 1.00 at June 30, 2010. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 100.07 to 1.00 at June 30, 2010. At June 30, 2010, the $700,000 facility had $66,350 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $618,737 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 2.69% as of June 30, 2010.

NOTE 10—LONG-TERM DEBT:


	June 30, 2010		December 31, 2009
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	—
Senior notes due April 2020 at 8.25%, issued at par value		1,250,000		—
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $345 and $447 at June 30, 2010 and December 31, 2009, respectively)		249,655		249,553
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%		30,865		30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%		72,000		72,000
Advance royalty commitments (7.36% weighted average interest rate for June 30, 2010 and December 31, 2009)		35,176		35,547
Notes due through 2011 at 6.10%		12,372		14,628
Other long-term notes maturing at various dates through 2031 (total value of $154 and $164 less unamortized discount of $2 and $4 at June 30, 2010 and December 31, 2009 respectively)		152		160

		3,150,220		402,753
Less amounts due in one year		39,141		39,024

Long-Term Debt	$	3,111,079	$	363,729

NOTE 11—COMMITMENTS AND CONTINGENCIES:

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

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

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

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the

Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.

The current estimated cost of remedial action for the area that CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $64,000. The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $11,000. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was $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. There was $1,120 and $3,456 of expense recognized in cost of goods sold for the three and six months ended June 30, 2009, respectively. CONSOL Energy funded $1,209 and $4,000 in the six months ended June 30, 2010 and 2009, respectively, to an independent trust established for this remediation. The remaining liability at June 30, 2010 of $7,587 is reflected in Other Accrued Liabilities.

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

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

Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company (“Yukon”) filed an action on March 22, 2004 (the “Yukon Action”) against CCC related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs were seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, and to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group also filed a demand for arbitration (the “2008 Arbitration”) against ICCC which made similar claims relating to breach of the lease for water deposits and lost coal claims. All of the foregoing claims have been settled through a $75,000 cash payment made to the plaintiffs. The payment represented $25,000 of damages, $15,000 and $25,000 of expense was recognized in the three and six months ended June 30, 2010, respectively, and $50,000 for the purchase of coal reserves and an advance mining royalty on leased coal reserves.

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

In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in

response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

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

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill and continuing thereafter, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection (“WVDEP”) that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC’s discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. Pursuant to the December 18, 2009 WVDEP Unilateral Order, CCC submitted a plan and schedule to WVDEP which provides for construction of a centralized advanced technology mine water treatment plant by May 31, 2013 to achieve compliance with chloride effluent limits and in-stream chloride water quality standards. The cost of the treatment plant may reach or exceed $100,000. Additionally, CCC is currently negotiating a joint Consent Decree with the EPA and the WVDEP that is likely to include the compliance plan and schedule that was submitted to WVDEP. The December 18, 2009 WVDEP unilateral Order was replaced by another unilateral Order that became effective on April 30, 2010 and will extend until October 31, 2010, unless replaced by the joint WVDEP/EPA consent decree that is being negotiated. The Consent Decree is also likely to include civil penalties to settle alleged past violations related to chlorides without an admission of liability. The parties have not yet discussed the amount of a civil penalty. The Consent Decree will provide CCC with a schedule for orderly construction of the advanced water treatment plant and related facilities. If we are required to comply with in-stream chloride limits on an accelerated basis or if we enter into a Consent Decree that includes a civil penalty, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

CONSOL Energy has been named as a defendant in five punitive class actions brought by alleged shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own. The cases are: Schurr v. CONSOL Energy and others (No. 2010-2333), filed in the Court of Common Pleas of Washington County, Pennsylvania on March 29, 2010; Gummel v. CONSOL Energy (No. 5377-VCL), filed March 29, 2010 in the Delaware Court of Chancery; Polen v. CONSOL Energy and others (No. 2010-2626), filed in the Court of Common Pleas of Washington County, Pennsylvania on April 12, 2010; Gaines v. CONSOL Energy and others (No. 5378), filed

March 30, 2010 in the Delaware Court of Chancery; and Hurwitz v. CONSOL Energy and others (NO. 5405), filed in the Delaware Court of Chancery on April 13, 2010. Other than the Gummel case, the suits also name CNX Gas and certain officers and directors of CONSOL Energy and CNX Gas as defendants. All five actions generally allege that CONSOL Energy has breached and/or has aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders. Among other things, the actions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys’ fees and expenses. The Pennsylvania lawsuits have been stayed and the Delaware lawsuits have been consolidated. The Delaware Court of Chancery denied an injunction against the tender offer and CONSOL Energy acquired all of the outstanding shares of CNX Gas. The Delaware Court of Chancery certified to the Delaware Supreme Court the question of what standard should be applied to the tender offer, which would determine whether the shareholders can proceed with a damage claim. The Delaware Supreme Court declined to accept the appeal pending a final judgment. Therefore, the lawsuit will likely go through a fact discovery phase and, later, trial. CONSOL Energy believes that these actions are without merit and intends to defend them vigorously. We cannot predict the ultimate outcome of this litigation; however, if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

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 have increased. Changes in mining have increased the quantity of material required to reclaim the affected area. As of this time, no detailed reclamation plan has been developed and the definitive costs associated with the increased reclamation are not available, however, our estimates indicate the reclamation liability could equal or exceed $65,000. As a result, $27,900 and $52,900 of expense was recognized in the three and six months ended June 30, 2010, respectively. Detailed reclamation plans and mining plans are being developed to determine the impacts of these revised plans on the associated reclamation liability. It is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to Fola reclamation may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

On February 14, 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. In April 2010, CNX Gas and GeoMet entered into an agreement involving the exchange of less than 800 acres of coalbed methane rights in Virginia and the grant by Consolidation Coal Company to GeoMet of consent to stimulate the coal seam on certain of GeoMet’s drilling units in Virginia. This litigation was settled as part of that transaction. CNX Gas did not pay any amount to GeoMet in connection with the settlement of this litigation.

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

The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit

and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

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

At June 30, 2010, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.


	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	198,823	$	198,823	$	—	$	—	$	—
Environmental		57,471		57,471		—		—		—
Gas		14,913		14,913		—		—		—
Other		11,764		11,600		164		—		—

Total Letters of Credit		282,971		282,807		164		—		—

Surety Bonds:
Employee-Related		193,251		181,751		11,500		—		—
Environmental		369,480		345,218		24,262		—		—
Gas		6,335		6,192		142		—		1
Other		9,604		9,591		13		—		—

Total Surety Bonds		578,670		542,752		35,917		—		1

Guarantees:
Coal		160,790		97,045		57,506		1,239		5,000
Gas		68,206		42,601		22,505		—		3,100
Other		409,157		72,052		111,802		79,534		145,769

Total Guarantees		638,153		211,698		191,813		80,773		153,869

Total Commitments	$	1,499,794	$	1,037,257	$	227,894	$	80,773	$	153,870

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


Obligations Due	Amount
Less than 1 year	$	93,016
1 - 3 years		186,645
3 - 5 years		85,476
More than 5 years		326,558

Total Purchase Obligations	$	691,695

Expenses related to these purchase obligations include:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Major equipment purchases	$	8,946	$	5,670	$	27,151	$	69,053
Firm transportation expense		9,408		5,133		16,103		9,719
Gas drilling obligations		832		—		1,437		—
Other		150		30		180		60

Total expense related to purchase obligations	$	19,336	$	10,833	$	44,871	$	78,832

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 year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

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

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

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

As of June 30, 2010, the total notional amount of the Company’s outstanding natural gas forward contracts was 59.5 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $41,652 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of June 30, 2010, CONSOL Energy did not have any outstanding coal sales options. For the three and six months ended June 30, 2009, CONSOL Energy recognized, in Other Income on the Consolidated Statements of Income, a gain of $203 and $2,338 respectively for the coal sales options which were not designated as hedging instruments.

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


	Derivatives As of June 30, 2010
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	68,662
Natural Gas Price Swaps	Other Assets		34,987

Total derivatives designated as hedging instruments		$	103,649

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

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 Gain 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

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


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

Total derivatives designated as hedging instruments		$	117,483

The effect of derivative instruments on the Consolidated Statements of Income for the three months ended June 30, 2009 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2009		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2009		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps	$	30,394	Outside Sales	$	66,120	Outside Sales	$	(494	)

The effect of derivative instruments on the Consolidated Statements of Income for the six months ended June 30, 2009 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2009		Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2009		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps	$	109,342	Outside Sales	$	116,738	Outside Sales	$	(869	)

NOTE 13—OTHER COMPREHENSIVE LOSS:

Total comprehensive income (loss), net of tax, for the six months ended June 30, 2010 was as follows:


	Treasury Rate Lock			Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Adjustments for Non- controlling Interest			Accumulated Other Comprehensive Loss
Balance at December 31, 2009	$	180		$	71,378		$	(699,293	)	$	(12,769	)	$	(640,504	)
Net increase in value of cash flow hedges		—			89,528			—			(12,500	)		77,028
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(98,082	)		—			7,248			(90,834	)
Elimination of noncontrolling interest from purchase of CNX Gas		—			—			—			18,026			18,026
Current period change		(44	)		—			9,393			(5	)		9,344

Balance at June 30, 2010	$	136		$	62,824		$	(689,900	)	$	—		$	(626,940	)

NOTE 14—FAIR VALUES OF FINANCIAL INSTRUMENTS:

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


	Fair Value Measurements at June 30, 2010
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	103,649	$	—

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

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

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

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

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


	June 30, 2010						December 31, 2009
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	34,313		$	34,313		$	65,607		$	65,607
Short-term notes payable	$	(358,550	)	$	(358,550	)	$	(472,850	)	$	(472,850	)
Borrowings Under Securitization Facility	$	(200,000	)	$	(200,000	)	$	(50,000	)	$	(50,000	)
Long-term debt	$	(3,150,220	)	$	(3,278,647	)	$	(402,753	)	$	(420,056	)

NOTE 15—SEGMENT INFORMATION:

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Steam, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the six months ended June 30, 2010, the Steam aggregated segment includes the following mines: Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the six months ended June 30, 2010, the Low Volatile Metallurgical aggregated segment includes the Buchanan mine. For the six months ended June 30, 2010, the High Volatile Metallurgical aggregated segment includes: Bailey, Enlow Fork, Fola Complex and Emery coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas unit includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Conventional and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas segment but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2009 segment information have been made to conform to the 2010 presentation. These reclassifications include changes to the coal operating segments the addition of the Gas operating segments.

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	$	745,597	$	149,145	$	55,655	$	6,097		$	956,494	$	149,305	$	10,399	$	29,998	$	1,727		$	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	$	745,597	$	149,145	$	55,655	$	34,172		$	984,569	$	149,305	$	10,399	$	29,998	$	18,314		$	208,016	$	115,759	$	(44,262	)	$	1,264,082

Earnings (Loss) Before Income Taxes	$	130,146	$	84,790	$	25,525	$	(121,938	)	$	118,523	$	70,590	$	265	$	2,864	$	(19,526	)	$	54,193	$	5,227	$	(81,795	)	$	96,148	(A)

Segment assets										$	4,946,425										$	5,818,535	$	311,613	$	611,518		$	11,688,091	(B)

Depreciation, depletion and amortization										$	79,424										$	48,953	$	4,387	$	—		$	132,764

Capital expenditures										$	185,343										$	3,599,145	$	3,458	$	—		$	3,787,946

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

(B)	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 three months ended June 30, 2009 are:


	Steam		Low Volatile Metallurgical			High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale			Conventional Gas		Other Gas			Total Gas		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—Outside	$	759,529	$	15,226		$	—	$	8,111		$	782,866	$	142,971	$	3,688		$	2,788	$	1,310		$	150,757	$	60,518		$	—		$	994,141
Sales—Purchased Gas		—		—			—		—			—		—		—			—		1,166			1,166		—			—			1,166
Sales—Gas Royalty Interests		—		—			—		—			—		—		—			—		8,666			8,666		—			—			8,666
Freight—Outside		—		—			—		27,087			27,087		—		—			—		—			—		—			—			27,087
Intersegment transfers		—		—			—		—			—		—		—			—		107			107		37,664			(37,771	)		—

Total Sales and Freight	$	759,529	$	15,226		$	—	$	35,198		$	809,953	$	142,971	$	3,688		$	2,788	$	11,249		$	160,696	$	98,182		$	(37,771	)	$	1,031,060

Earnings (Loss) Before Income Taxes	$	220,297	$	(15,416	)	$	—	$	(66,769	)	$	138,112	$	70,073	$	(295	)	$	194	$	(16,761	)	$	53,211	$	(3,808	)	$	(14,260	)	$	173,255	(C)

Segment assets											$	4,382,989											$	2,182,678	$	324,952		$	466,681		$	7,357,300	(D)

Depreciation, depletion and amortization											$	77,585											$	24,883	$	5,007		$	—		$	107,475

Capital expenditures											$	111,961											$	80,213	$	4,685		$	—		$	196,859

(C)	Includes equity in earnings of unconsolidated affiliates of $1,046, $295 and $2,098 for Coal, Gas and All Other, respectively.

(D)	Includes investments in unconsolidated equity affiliates of $11,419, $24,511 and $41,776 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	$	1,462,320	$	275,602	$	113,022	$	29,160		$	1,880,104	$	310,348	$	18,382	$	32,570	$	3,276		$	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	$	1,462,320	$	275,602	$	113,022	$	88,435		$	1,939,379	$	310,348	$	18,382	$	32,570	$	38,084		$	399,384	$	232,120	$	(88,732	)	$	2,482,151

Earnings (Loss) Before Income Taxes	$	299,180	$	133,376	$	55,780	$	(254,762	)	$	233,574	$	151,617	$	2,347	$	2,899	$	(28,985	)	$	127,878	$	6,635	$	(129,771	)	$	238,316	(E)

Segment assets										$	4,946,425										$	5,818,535	$	311,613	$	611,518		$	11,688,091	(F)

Depreciation, depletion and amortization										$	161,748										$	81,045	$	9,157	$	—		$	251,950

Capital expenditures										$	384,668										$	3,664,459	$	4,163	$	—		$	4,053,290

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

(F)	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, 2009 are:


	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—Outside	$	1,594,592	$	84,769	$	—	$	21,741		$	1,701,102	$	301,189	$	5,283	$	4,433		$	1,759		$	312,664	$	130,619	$	—		$	2,144,385
Sales—Purchased Gas		—		—		—		—			—		—		—		—			2,631			2,631		—		—			2,631
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—			21,298			21,298		—		—			21,298
Freight—Outside		—		—		—		58,003			58,003		—		—		—			—			—		—		—			58,003
Intersegment transfers		—		—		—		—			—		—		—		—			542			542		75,183		(75,725	)		—

Total Sales and Freight	$	1,594,592	$	84,769	$	—	$	79,744		$	1,759,105	$	301,189	$	5,283	$	4,433		$	26,230		$	337,135	$	205,802	$	(75,725	)	$	2,226,317

Earnings (Loss) Before Income Taxes	$	487,605	$	7,995	$	—	$	(158,842	)	$	336,758	$	160,039	$	149	$	(68	)	$	(17,479	)	$	142,641	$	4,138	$	(25,576	)	$	457,961	(G)

Segment assets										$	4,382,989											$	2,182,678	$	324,952	$	466,681		$	7,357,300	(H)

Depreciation, depletion and amortization										$	155,790											$	47,702	$	10,202	$	—		$	213,694

Capital expenditures										$	272,896											$	213,763	$	9,760	$	—		$	496,419

(G)	Includes equity in earnings of unconsolidated affiliates of $2,474, $557 and $3,769 for Coal, Gas and All Other, respectively.

(H)	Includes investments in unconsolidated equity affiliates of $11,419, $24,511 and $41,776 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,
	2010			2009			2010			2009
Segment Earnings Before Income Taxes for total reportable business segments	$	172,716		$	191,323		$	361,452		$	479,399
Segment Earnings Before Income Taxes for all other businesses		5,227			(3,808	)		6,635			4,138
Interest income (expense), net and other non-operating activity (I)		(67,732	)		(6,754	)		(69,273	)		(15,186	)
Acquisition and Financing Fees (I)		(14,187	)		—			(60,750	)		—
Operating lease cease-use		124			(7,543	)		252			(7,543	)
Corporate Restructuring (I)		—			37			—			(2,847	)

Earnings Before Income Taxes	$	96,148		$	173,255		$	238,316		$	457,961


Total Assets	June 30,
Total Assets	2010		2009

Segment assets for total reportable business segments	$	10,764,960	$	6,565,667
Segment assets for all other businesses		311,613		324,952
Items excluded from segment assets:
Cash and other investments (I)		33,826		101,206
Recoverable income taxes		36,145		—
Deferred tax assets		488,278		364,614
Bond issuance costs		53,269		861

Total Consolidated Assets	$	11,688,091	$	7,357,300

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $250,000, 7.875% per annum notes due March 1, 2012, the $1,500,000, 8.000% per annum notes due April 1, 2017, and the $1,250,000, 8.250% per annum notes due April 1, 2020 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, 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 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the three months ended 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)		84,499			528		14,450			7,941			(82,153	)		25,265

Total Revenue and Other Income		84,499			208,543		1,025,256			54,655			(83,606	)		1,289,347
Cost of Goods Sold and Other Operating Charges		23,114			59,087		684,569			(380	)		52,381			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	)		44,815			(42,677	)		—
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		(19,084	)		54,101		137,151			8,487			(84,507	)		96,148
Income Tax Expense (Benefit)		(39,188	)		20,608		40,271			3,557			—			25,248

Net Income (Loss)		20,104			33,493		96,880			4,930			(84,507	)		70,900
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—			(4,232	)		(4,232	)

Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	20,104		$	33,493	$	96,880		$	4,930		$	(88,739	)	$	66,668

Balance Sheet at June 30, 2010 (unaudited):


	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	28,358	$	1,041		$	3,294		$	1,620	$	—		$	34,313
Accounts and Notes Receivable:
Trade		—		61,407			391			183,998		—			245,796
Securitized		200,000		—			—			—		—			200,000
Other		3,024		1,600			5,556			4,702		—			14,882
Inventories		2		3,296			245,938			44,614		—			293,850
Recoverable Income Taxes		41,261		(5,116	)		—			—		—			36,145
Deferred Income Taxes		109,063		(22,863	)		—			—		—			86,200
Prepaid Expenses		32,126		74,476			22,653			3,403		—			132,658

Total Current Assets		413,834		113,841			277,832			238,337		—			1,043,844
Property, Plant and Equipment:
Property, Plant and Equipment		162,066		6,125,043			8,277,185			25,298		—			14,589,592
Less-Accumulated Depreciation, Depletion and Amortization		88,699		516,966			4,044,457			17,194		—			4,667,316

Property, Plant and Equipment-Net		73,367		5,608,077			4,232,728			8,104		—			9,922,276
Other Assets:
Deferred Income Taxes		764,394		(362,316	)		—			—		—			402,078
Investment in Affiliates		8,275,199		23,866			972,266			7,105		(9,191,312	)		87,124
Other		126,317		44,367			50,908			11,177		—			232,769

Total Other Assets		9,165,910		(294,083	)		1,023,174			18,282		(9,191,312	)		721,971

Total Assets	$	9,653,111	$	5,427,835		$	5,533,734		$	264,723	$	(9,191,312	)	$	11,688,091

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	76,623	$	83,126		$	93,440		$	11,900	$	—		$	265,089
Accounts Payable (Recoverable)—Related Parties		2,160,512		7,223			(2,318,340	)		150,605		—			—
Short-Term Notes Payable		292,200		66,350			—			—		—			358,550
Current Portion Long-Term Debt		584		9,197			36,063			460		—			46,304
Accrued Income Taxes		—		—			—			—		—			—
Borrowings under Securitization Facility		200,000		—			—			—		—			200,000
Other Accrued Liabilities		661,718		40,754			28,773			6,995		—			738,240

Total Current Liabilities		3,391,637		206,650			(2,160,064	)		169,960		—			1,608,183
Long-Term Debt:		3,000,315		62,006			106,009			619		—			3,168,949
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—		6,864			2,681,258			—		—			2,688,122
Pneumoconiosis		—		—			187,285			—		—			187,285
Mine Closing		—		—			390,214			—		—			390,214
Gas Well Closing		—		63,576			50,249			—		—			113,825
Workers’ Compensation		—		—			156,398			22		—			156,420
Salary Retirement		165,127		—			—			—		—			165,127
Reclamation		—		—			51,902			—		—			51,902
Other		63,450		36,608			33,906			7		—			133,971

Total Deferred Credits and Other Liabilities		228,577		107,048			3,551,212			29		—			3,886,866
Total Consol Energy Inc. Stockholders’ Equity		3,032,582		5,060,621			4,028,087			94,115		(9,182,822	)		3,032,583
Noncontrolling Interest		—		(8,490	)		8,490			—		(8,490	)		(8,490	)

Total Liabilities and Stockholders’ Equity	$	9,653,111	$	5,427,835		$	5,533,734		$	264,723	$	(9,191,312	)	$	11,688,091

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


	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	150,863	$	799,027	$	44,686	$	(435	) $		994,141
Sales—Purchased Gas		—			1,166		—		—		—			1,166
Sales—Gas Royalty Interests		—			8,666		—		—		—			8,666
Freight—Outside		—			—		27,087		—		—			27,087
Other Income (including equity earnings)		140,605			913		26,225		5,669		(133,907	)		39,505

Total Revenue and Other Income		140,605			161,608		852,339		50,355		(134,342	)		1,070,565
Cost of Goods Sold and Other Operating Charges		28,843			53,039		462,973		43,993		54,008			642,856
Purchased Gas Costs		—			390		—		—		—			390
Gas Royalty Interests’ Costs		—			6,470		—		—		(12	)		6,458
Related Party Activity		2,972			—		34,229		359		(37,560	)		—
Freight Expense		—			—		27,087		—		—			27,087
Selling, General and Administrative Expense		—			18,366		32,473		341		(15,553	)		35,627
Depreciation, Depletion and Amortization		3,284			24,883		78,643		665		—			107,475
Interest Expense		3,147			1,931		1,951		4		(88	)		6,945
Taxes Other Than Income		1,536			3,406		64,831		699		—			70,472

Total Costs		39,782			108,485		702,187		46,061		795			897,310

Earnings (Loss) Before Income Taxes		100,823			53,123		150,152		4,294		(135,137	)		173,255
Income Tax Expense (Benefit)		(12,516	)		20,146		45,162		1,624		—			54,416

Net Income (Loss)		113,339			32,977		104,990		2,670		(135,137	)		118,839
Less: Net Income Attributable to Noncontrolling Interest		—			—		—		—		(5,500	)		(5,500	)

Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	113,339		$	32,977	$	104,990	$	2,670	$	(140,637	)	$	113,339

Balance Sheet at December 31, 2009:


	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	59,549	$	1,124		$	3,764		$	1,170	$	—		$	65,607
Accounts and Notes Receivable:
Trade		—		43,421			113			273,926		—			317,460
Securitized		50,000		—			—			—		—			50,000
Other		4,781		975			3,281			6,946		—			15,983
Inventories		—		—			262,755			44,842		—			307,597
Deferred Income Taxes		108,254		(34,871	)		—			—		—			73,383
Prepaid Expenses		18,979		103,094			36,767			2,166		—			161,006

Total Current Assets		241,563		113,743			306,680			329,050		—			991,036
Property, Plant and Equipment:
Property, Plant and Equipment		162,145		2,409,751			8,082,159			27,900		—			10,681,955
Less-Accumulated Depreciation, Depletion and Amortization		82,733		433,201			4,022,295			19,436		—			4,557,665

Property, Plant and Equipment-Net		79,412		1,976,550			4,059,864			8,464		—			6,124,290
Other Assets:
Deferred Income Taxes		759,790		(334,493	)		—			—		—			425,297
Investment in Affiliates		4,399,823		24,591			797,269			3,921		(5,142,071	)		83,533
Other		84,736		21,627			33,216			11,666		—			151,245

Total Other Assets		5,244,349		(288,275	)		830,485			15,587		(5,142,071	)		660,075

Total Assets	$	5,565,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,775,401

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	93,876	$	53,516		$	114,872		$	7,296	$	—		$	269,560
Accounts Payable (Recoverable)—Related Parties		2,117,616		5,171			(2,378,119	)		255,332		—			—
Short-Term Notes Payable		415,000		57,850			—			—		—			472,850
Current Portion Long-Term Debt		501		8,616			35,853			424		—			45,394
Accrued Income Taxes		27,944		31,765			(31,765	)		—		—			27,944
Borrowings under Securitization Facility		50,000		—			—			—		—			50,000
Other Accrued Liabilities		546,066		25,455			34,569			6,748		—			612,838

Total Current Liabilities		3,251,003		182,373			(2,224,590	)		269,800		—			1,478,586
Long-Term Debt:		250,255		65,690			106,369			594		—			422,908
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—		3,642			2,675,704			—		—			2,679,346
Pneumoconiosis		—		—			184,965			—		—			184,965
Mine Closing		—		—			397,320			—		—			397,320
Gas Well Closing		—		8,312			77,680			—		—			85,992
Workers’ Compensation		—		—			152,486			—		—			152,486
Salary Retirement		189,697		—			—			—		—			189,697
Reclamation		—		—			27,105			—		—			27,105
Other		88,821		35,101			8,595			—		—			132,517

Total Deferred Credits and Other Liabilities		278,518		47,055			3,523,855			—		—			3,849,428
Total Consol Energy Inc. Stockholders’ Equity		1,785,548		1,511,270			3,787,025			82,707		(5,381,002	)		1,785,548
Noncontrolling Interest		—		(4,370	)		4,370			—		238,931			238,931

Total Liabilities and Stockholders’ Equity	$	5,565,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,775,401

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			3,027		118,097		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	)		89,332		(83,229	)	—
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

Income Statement for the Six Months Ended June 30, 2009 (unaudited):


	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	313,203	$	1,737,451	$	95,166	$	(1,435	)$		2,144,385
Sales—Purchased Gas		—			2,631		—		—		—			2,631
Sales—Gas Royalty Interests		—			21,298		—		—		—			21,298
Freight—Outside		—			—		58,003		—		—			58,003
Other Income (including equity earnings)		354,964			2,860		38,969		11,631		(345,425	)		62,999

Total Revenue and Other Income		354,964			339,992		1,834,423		106,797		(346,860	)		2,289,316
Cost of Goods Sold and Other Operating Charges		47,339			86,389		981,180		91,835		103,735			1,310,478
Purchased Gas Costs		—			1,920		—		—		—			1,920
Gas Royalty Interests’ Costs		—			17,071		—		—		(22	)		17,049
Related Party Activity		3,519			—		62,387		787		(66,693	)		—
Freight Expense		—			—		58,003		—		—			58,003
Selling, General and Administrative Expense		—			34,616		58,566		666		(27,405	)		66,443
Depreciation, Depletion and Amortization		6,627			47,702		159,893		1,326		(1,854	)		213,694
Interest Expense		6,972			3,888		4,763		8		(174	)		15,457
Taxes Other Than Income		3,416			5,939		137,608		1,348		—			148,311

Total Costs		67,873			197,525		1,462,400		95,970		7,587			1,831,355

Earnings (Loss) Before Income Taxes		287,091			142,467		372,023		10,827		(354,447	)		457,961
Income Tax Expense (Benefit)		(22,067	)		54,586		97,536		4,096		—			134,151

Net Income (Loss)		309,158			87,881		274,487		6,731		(354,447	)		323,810
Less: Net Income Attributable to Noncontrolling Interest		—			—		—		—		(14,652	)		(14,652	)

Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	309,158		$	87,881	$	274,487	$	6,731	$	(369,099	)	$	309,158

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


	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by (Used In) 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	)
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 Borrowing		(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
Other Financing Activities		(68,967	)		6,609			(11,653	)		(257	)		—		(74,268	)

Net Cash Provided by (Used in) Financing Activities	$	4,496,401		$	15,109		$	(11,653	)	$	(257	)	$	—	$	4,499,600

Cash Flow for the Six Months Ended June 30, 2009 (unaudited):


	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	111,297		$	214,075		$	239,235		$	1,639		$	—	$	566,246

Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(213,763	)	$	(282,656	)	$	—		$	—	$	(496,419	)
Investment in Equity
Affiliates		—			1,250			840			—			—		2,090
Other Investing Activities		—			245			47,939			—			—		48,184

Net Cash Used in Investing Activities	$	—		$	(212,268	)	$	(233,877	)	$	—		$	—	$	(446,145	)

Cash Flows from Financial Activities:
Dividends Paid	$	(36,128	)	$	—		$	—		$	—		$	—	$	(36,128	)
Proceeds from (Payments on) Short Term Borrowing		(114,000	)		8,300			—			—			—		(105,700	)
Other Financing Activities		765			(4,463	)		(4,532	)		(244	)		—		(8,474	)

Net Cash Provided by (Used in) Financing Activities	$	(149,363	)	$	3,837		$	(4,532	)	$	(244	)	$	—	$	(150,302	)

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:

In April 2010, the Financial Accounting Standards Board issued an update to the Revenue Recognition – Milestone Method Topic of the FASB Accounting Standards Codification which is effective for CONSOL Energy on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010. This update is intended to provide additional application guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research and development transactions. This new guidance does not have a material impact on CONSOL Energy’s financial statements for the current period, nor do we believe that it will have a material impact on the financial statements in future periods.

In April 2010, the Financial Accounting Standards Board issued an update to the Extractive Activities – Oil and Gas Topic of the FASB Accounting Standards Codification which is intended to revise definitions as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. This guidance has been considered during the preparation of the financial statements; however, we believe that the adoption of this new guidance will not have a material impact on CONSOL Energy’s financial statements.

In April 2010, the Financial Accounting Standards Board issued an update to the Compensation – Stock Compensation Topic of the FASB Accounting Standards Codification which is effective for CONSOL Energy beginning December 15, 2010. This update is intended to address the classification of employee share-based payment award with an exercise price denominated in the currency of the market in which the underlying equity security trades. This update affects entities that issue employee share-based payment awards with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades that differs from the functional currency of the employer entity or payroll currency of the employee. As CONSOL Energy does not issue such awards in a currency which differs from the entity’s functional currency, we believe that this new guidance will not have an impact on the financial statements.

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

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The U.S. metallurgical coal market has eased recently, as steel production has slightly outpaced demand. Steel mill utilization is currently at 72%, down from 73% three months ago. Through June, global blast furnace iron production is up approximately 27% over 2009 levels and steel mill capacity utilization is currently at 80% in Europe and 84% in China. In the global market, steel demand for the balance of 2010 through 2011 is expected to remain at current levels in Europe and North America due to uncertainty in the global economy. China which has been the driver for both steel production and consumption has taken steps to slow its rate of growth, contributing to short term softening in metallurgical coal demand. However, forecasts for the rate of growth of the Chinese economy remain close to 10% for 2010 and 8.5% for 2011. Given the continued projected growth in the Chinese economy, shortage of high quality metallurgical coal and relatively low steel inventories, we anticipate that metallurgical coal markets will continue to provide strong long-term pricing similar to what we have seen in the first half of 2010.

The thermal coal outlook continues to improve due to unseasonably hot weather in the eastern U.S., declining inventories and increasing industrial activity. Inventories at utilities in our major market area (Mid Atlantic and South Atlantic markets) are lower than in other regions of the U.S. with inventories at some plants below 30 days of burn as of the end of June. The thermal coal market in Northern Appalachia is also being strengthened by CONSOL Energy’s exporting of coal from its Northern Appalachian mines to Asia (as high-vol coking coal) and to Europe (as thermal coal). Longer term, exports of thermal coal look increasingly more favorable driven by economic growth in developing countries like China and India and shifting of traditional supply to meet these growth demands. Regulatory pressures in Central Appalachia continue to reduce coal supply as permits become increasingly more difficult to obtain and costs increase. CONSOL Energy estimates that annual production from Central Appalachia will decline another 40 million tons by 2015. The issues in Central Appalachia combined with a general economic recovery are expected to increase coal sales opportunities and expand market share for CONSOL Energy in both the short and long term. CONSOL Energy’s low cost Northern Appalachian mining operations are well positioned to replace production declines in Central Appalachia.

The U.S. natural gas industry continues to face concerns of oversupply, which are holding down gas prices. The supply of natural gas remains very strong due to the success of new shale plays. Some of this over supply is due to drilling commitments from leases in the shale plays. In addition, demand has not recovered to pre-recession levels. However, there are increasing signs of improvement in the gas markets. The summer 2010 cooling season has helped slow storage build compared to 2009 levels. Industrial demand is building and although not to pre-recession levels, the industrial load has grown slowly for five straight months. In addition to these increases in demand, there have been supply responses to the current price environment. We have seen a decrease in Canadian gas imports and the expected wave of LNG imports has failed to materialize. We expect the drilling activity to fulfill lease commitments in the shale plays to slow in 2011 and beyond so that future drilling will be driven more by economic returns. The current disaster in the Gulf of Mexico also raises questions about gas production from deepwater drilling and possibly all offshore production. These factors are reflected in current NYMEX strip pricing for natural gas with prices expected to recover to the mid $5s by 2012. CONSOL Energy’s position in the Marcellus shale will allow CONSOL Energy to remain profitable in the current pricing environment due to the basis premium for being close to important Northeast markets, the low cost of Marcellus shale production and CONSOL Energy’s position as a low cost producer within the Marcellus shale play.

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

•

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

•

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

•

On April 1, 2010, the Environmental Protection Agency (EPA) issued detailed guidance to its regional offices to provide clarification of the EPA’s expectations regarding the EPA review of permits necessary for coal mining activities in the states of Kentucky, West Virginia, Pennsylvania, Virginia, Ohio and Tennessee. The guidance pertains to the EPA’s review of proposed surface water discharge (NPDES) permits under Section 402 of the Clean Water Act, proposed permits for filling waters of the United States under Section 404 of the Clean Water Act, and the National Environmental Policy Act (NEPA) review of projects covered by NEPA. In the guidance, the EPA creates a number of presumptions and instructs the regional offices to object to permits if the presumptions are implicated. One presumption is that conductivity levels above 500 microSiemens per centimeter in streams below coal mining operations are harmful to aquatic insects and therefore violate state water quality standards. The 500 microSiemens presumption is at least three times lower than the conductivity level that results from using the EPA’s standard protocol for determining toxicity to aquatic life. (Conductivity is a measurement of the concentration of ionized materials in water.) If this presumption is strictly applied, it will take longer to obtain NPDES permits and valley fill permits for mining operations, or permit applications may be denied. The guidance is likely to be challenged by the coal industry. It is too early to determine the impact of this policy if it remains in effect, but it could materially adversely affect our operations and results of operations.

•

Under existing Mine Health and Safety Administration regulations, the installation of higher strength seals to isolate abandoned areas or previously sealed areas of the mine is required. The increase in strength of seals was required to better protect the active sections of the underground mines from explosions, fires, or other situations that may occur within the sealed areas. CONSOL Energy has been

replacing existing seals with the higher strength seals over the past two years. We currently estimate approximately 540 seals remaining that need to be replaced over the next two years. The cost of these seals is expensed as incurred.

•

As described more fully in “Note 11—Commitments and Contingencies” in Item I, Condensed Consolidated Financial Statements of this Form 10-Q, Consolidation Coal Company (CCC) has submitted to the West Virginia Department of Environmental Protection (WVDEP) a plan and schedule which provides for construction of a centralized advanced technology mine water treatment plant by June 2013 to achieve compliance with chloride effluent limits and in-stream chloride water quality standards in tributaries to the Monongahela River. The cost of the treatment plant may reach or exceed $100,000. Additionally, CCC is currently negotiating a joint Consent Decree with the EPA and the WVDEP that is likely to include the compliance plan and schedule that was submitted to the WVDEP. The Consent Decree is also likely to include civil penalties to settle alleged past violations related to chlorides without an admission of liability. The parties have not yet discussed the amount of a civil penalty. The Consent Decree will provide CCC with a schedule for orderly construction of the advanced water treatment plant and related facilities.

•

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

•

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

•

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

•

The EPA has announced that it will conduct a comprehensive study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formations such as the Barnett and Marcellus shales. The study is the result of identification of the need for such a study in the Fiscal Year 2010 budget report of the U. S. House of Representatives Appropriation Conference Committee. The EPA plans to complete the study

design by September 2010, initiate the study in January 2011 and have the initial study results available by late 2012. It is too early to predict what actions, if any, will result from the study.

•

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act became law. The legislation, among other matters, establishes a consumer financial bureau within the Federal Reserve, creates a financial stability oversight counsel, imposes centralized clearing for financial swap transactions and regulates swap dealers and major swap participants, grants shareholders a nonbinding vote on executive compensation, and provides the government with the power to take over certain businesses whose failure would damage the economy. The impacts of the legislation on CONSOL Energy may include less availability and higher costs of additional credit and borrowing capacity, increased scrutiny of corporate governance, and added reporting requirements.

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

•

Our low-volatile metallurgical coal business with our Buchanan Coal Mine,

•

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

•

Our improved thermal business.

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

CONSOL Energy completed an equity offering on March 31, 2010 of 44.3 million shares of common stock, which generated net proceeds of approximately $1.8 billion. On April 1, 2010, CONSOL Energy issued $1.5 billion of 8% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020. Covenants in the Notes Indenture limit CONSOL Energy’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company. The equity and bond proceeds were used to complete the Dominion Acquisition for total consideration of approximately $3.5 billion. The acquisition closed on April 30, 2010.

On April 30, 2010, CONSOL Energy closed on the $3.5 billion Dominion Acquisition, with the fair value assigned primarily to the proved and unproven gas reserves and acres acquired. The assets include nearly 1 trillion cubic feet of proved reserves and nearly 500 thousand acres of Marcellus Shale. Nearly all of the Marcellus Shale acreage that was acquired is held by production. Such acreage has no drilling commitments, and therefore allows capital to be allocated on the basis of economics, not simply to hold expiring leases. The majority of the acquired acreage has a 12.5% royalty, except for about 20 thousand acres held in fee (meaning that it has no royalty). Nearly all of the Marcellus Shale acres are in southwestern Pennsylvania or northern West Virginia. The Pennsylvania Marcellus Shale acreage is concentrated in Indiana, Westmoreland, and Armstrong counties, while the West Virginia acreage is concentrated in Barbour, Lewis, and Upshur counties.

On May 28, 2010, CONSOL Energy completed a tender offer for all of the shares of CNX Gas common stock that it did not previously own at a cash price of $38.25 per share and on June 1, 2010, CONSOL Energy completed a short form merger to acquire for the same price those shares not tendered into the tender offer. CONSOL Energy paid $991 million to acquire approximately 25.3 million shares of CNX Gas common stock and outstanding vested stock options. Following the purchase by CONSOL Energy of shares of CNX Gas in the offer, CONSOL Energy merged CNX Gas into a wholly owned subsidiary of CONSOL Energy, with CNX Gas surviving the merger as a wholly owned subsidiary of CONSOL Energy. CONSOL Energy financed the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and proceeds from its recently closed offering of common stock.

On June 29, 2010, CONSOL Energy announced that J. Brett Harvey has been appointed as chairman of the board. Mr. Harvey will also remain President and Chief Executive Officer of the company. With this change, John Whitmire now becomes vice chairman of the board. In other action pertaining to the change, CONSOL Energy’s Board of Directors appointed Philip W. Baxter as the lead independent director.

Results of Operations

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

Net Income Attributable to CONSOL Energy

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $66.7 million, or $0.29 per diluted share, for the three months ended June 30, 2010. Net income attributable to CONSOL Energy shareholders was $113.3 million, or $0.62 per diluted share, for the three months ended June 30, 2009. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.

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

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

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

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

The coal segment contributed $120 of earnings before income taxes in the three months ended June 30, 2010 compared to $138 in the 2009 period. Variances by the individual coal segments are discussed below.


	Three Months Ended June 30, 2010											Difference to Three Months Ended June 30, 2009
	Steam Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam Coal			High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal
Sales:
Produced Coal	$	746	$	56	$	149	$	4		$	955	$	(13	)	$	56	$	133	$	4		$	180
Purchased Coal		—		—		—		2			2		—			—		—		(6	)		(6	)

Total Outside Sales		746		56		149		6			957		(13	)		56		133		(2	)		174
Freight Revenue		—		—		—		28			28		—			—		—		1			1
Other Income		3		2		—		12			17		2			2		—		(18	)		(14	)

Total Revenue and Other Income		749		58		149		46			1,002		(11	)		58		133		(19	)		161
Costs and Expenses:
Total operating costs		470		23		48		72			613		70			23		26		(20	)		99
Total provisions		47		2		6		38			93		7			2		2		56			67
Total administrative & other costs		40		2		5		22			69		3			2		3		1			9
Depreciation, depletion and amortization		64		3		5		7			79		1			3		2		(3	)		3

Total Cost and Expenses		621		30		64		139			854		81			30		33		34			178
Freight Expense		—		—		—		28			28		—			—		—		1			1

Total Cost		621		30		64		167			882		81			30		33		35			179

Earning Before Income Taxes	$	128	$	28	$	85	$	(121	)	$	120	$	(92	)	$	28	$	100	$	(54	)	$	(18	)

STEAM COAL SEGMENT

The steam coal segment contributed $128 million to total company earnings before income tax in the three months ended June 30, 2010 compared to $220 million in the three months ended June 30, 2009.

Steam coal revenue was $746 million in the three months ended June 30, 2010 compared to $759 million in the three months ended June 30, 2009. The $13 million decrease was attributable to lower average sales prices for steam coal, offset, in part, by higher steam coal tons sold.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		13.9		13.1		0.8		6.1	%
Average Sales Price Per Steam Ton	$	53.58	$	58.13	$	(4.55	)	(7.8	)%

Lower average sales prices for steam coal reflects the roll-off of higher priced contracts signed in the later half of 2008. Steam coal inventory was 2.9 million tons at June 30, 2010. Steam coal tons sold are higher in the period-to-period comparison due to the Shoemaker mine restarting production early in 2010 after being idled throughout the three months ended June 2009. The mine was idled in order to complete the replacement of the track haulage system to a more efficient belt haulage system. Steam coal tons sold were also higher due to the

Blacksville #2 Mine production increasing in the period-to-period comparison. Blacksville #2 was idled for most of three months ended June 2009 in order to manage inventory levels during the economic crisis experienced in 2009. These increases were offset, in part, by approximately 0.7 million tons of steam coal tons being sold on the high volatile (vol) metallurgical market at approximately $21.94 per ton higher sales price. Although the sale of these tons lowered the Steam Coal segment revenue by approximately $39 million, total company revenue increased by approximately $16 million.

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

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operation costs related to the steam coal segment were $470 million in the three months ended June 30, 2010 compared to $400 million in the three months ended June 30, 2009. Operating costs related to the steam coal segment have increased primarily due to higher average cost per ton sold and higher volumes sold.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced Steam Tons Sold (in millions)		13.9		13.1		0.8	6.1	%
Average Operating Costs Per Steam Ton	$	33.71	$	30.62	$	3.09	10.1	%

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

•

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

•

Health and retirement costs related to the active hourly work force have increased due to higher contributions to the multiemployer 1974 pension trust that is required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America (UMWA) in the three months ended June 30, 2009 to $5.00 per hour in the three months ended June 30, 2010. Contributions to the multiemployer plan are expensed as incurred. These costs have also increased in the period-to-period comparison due to higher medical costs for the active hourly work force.

•

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

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

•

Average operating costs per unit decreased due to higher tons sold. Fixed costs are spread over higher tons therefore decreasing average unit costs.

•

Labor dollars have increased in the period-to-period comparison, but dollars have not increased proportionately to tons sold. Therefore, average labor costs on a per unit basis have decreased. Labor dollars have increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-union mines. Employee counts have also increased approximately 6% at our active mining operations in order to meet our staffing needs.

•

Subsidence costs have decreased in the period-to-period comparison due mainly to timing of undermining structures and streams.

Total provisions are made up of the expenses related to the company’s long-term liabilities such as other post employment benefits (OPEB), the salary retirement plan, workers’ compensation, long term disability and mine closing and related liabilities. With the exception of mine closing and related liabilities accretion expense, these liabilities are actuarially calculated for the company as a whole. The expenses associated with these costs are allocated to operational units based on active employee counts or active salary dollars. Mine closing and related liabilities accretion is calculated on a mine-by-mine basis. The provision expense attributable to the steam coal segment was $47 million in the three months ended June 30, 2010 compared to $40 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced Steam Tons Sold (in millions)		13.9		13.1		0.8	6.1	%
Average Provision Costs Per Steam Ton	$	3.38	$	3.04	$	0.34	11.2	%

Total CONSOL Energy expenses related to our actuarial liabilities were $71 million in the three months ended June 30, 2010 compared to $57 million for the three months ended June 30, 2009. The increase of $14 million is due primarily to changes in the discount rates used at the measurement dates and changes in assumptions which affect the amount amortized into earnings.

Provision costs per unit have increased in the period-to-period comparison due primarily to the higher actuarial liability expenses for the total company explained above. Although the percentage of these expenses allocated to the steam coal segment is lower in the current quarter, the overall increase in company costs has increased the total dollars allocated to the steam coal segment proportionately more than the increase in the tons sold.

Total administrative and other costs include selling expenses, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to the mines on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Total administrative and other costs related to the steam coal segment were $40 million in the three months ended June 30, 2010 compared to $37 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced Steam Tons Sold (in millions)		13.9		13.1		0.8	6.1	%
Average Selling, Administrative and Other Costs Per Steam Ton	$	2.88	$	2.82	$	0.06	2.1	%

Total company selling, general and administrative costs, excluding commission, are flat in the period-to-period comparison. Commissions related to the steam coal segment have increased in the period-to-period comparison causing the average unit cost to increase. The increase is primarily due to additional tons sold.

Depreciation, depletion and amortization was $64 million in the three months ended June 30, 2010 compared to $63 million in the three months ended June 30, 2009 for the steam coal segment. Lower average unit costs were due to higher tons sold in the period-to-period comparison.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		13.9		13.1		0.8		6.1	%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton	$	4.59	$	4.84	$	(0.25	)	(5.2	)%

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

HIGH VOL METALLURGICAL COAL SEGMENT

The high vol metallurgical (met) coal segment contributed $28 million to total company earnings before income tax in the three months ended June 30, 2010. There was no activity in this segment in the prior period. This is a new market that has developed in 2010 and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical markets.

The high vol met coal segment sales revenue was $56 million in the three months ended June 30, 2010. Strength in the met coal market has allowed for the export of Northern Appalachian coal, historically sold domestically on the steam coal market, to crossover to the Brazil and Asia metallurgical coal markets.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		0.7		—		0.7	100.0	%
Average Sales Price Per High Vol Met Ton	$	75.52	$	—	$	75.52	100.0	%

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

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


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		0.7		—		0.7	100.0	%
Average Operating Costs Per High Vol Met Ton	$	30.50	$	—	$	30.50	100.0	%
Average Provision Costs Per High Vol Met Ton	$	3.19	$	—	$	3.19	100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton	$	2.81	$	—	$	2.81	100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton	$	4.37	$	—	$	4.37	100.0	%

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

LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical (met) coal segment contributed $85 million to the total company earnings before income tax in the three months ended June 30, 2010 compared to losing $15 million in the three months ended June 30, 2009. The increase is due primarily to the Buchanan Mine operating for the entire 2010 period. The Buchanan Mine was idled for the three months ended June 30, 2009 in response to the economic crisis in 2009 that significantly lowered the demand for low volatile coal. The lower demand for this coal in the 2009 period was due to a drop in steel demand.

The low vol met coal segment sales revenue was $149 million in the three months ended June 30, 2010 compared to $16 million in the three months ended June 30, 2009. Higher sales revenues were due to higher average sales prices and higher tons sold.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.0		0.1		0.9	900.0	%
Average Sales Price Per Low Vol Met Ton	$	149.38	$	113.71	$	35.67	31.4	%

Average sales prices for low vol met tons have increased 31.4% mainly due to the improvement in global economic conditions. The period-to-period comparison reflects higher demand for steel and steel related products which correspondingly has increased the demand for low vol metallurgical coal.

Total costs for the low vol coal met segment were $64 million in the three months ended June 30, 2010 compared to $31 million for the three months ended June 30, 2009. A meaningful comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low vol coal segment in 2009 as discussed above. The improvements in unit costs are related to operating the Buchanan mine throughout the three months ended June 30, 2010. The 2009 unit costs are not representative of the operating mine due to fixed costs being spread over significantly fewer tons. The 2010 period costs are representative of normal costs for this segment.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		1.0		0.1		0.9		900.0	%
Average Operating Costs Per Low Vol Met Ton	$	48.01	$	158.42	$	(110.42	)	(69.7	)%
Average Provision Costs Per Low Vol Met Ton	$	6.67	$	27.51	$	(20.84	)	(75.8	)%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton	$	5.10	$	18.06	$	(12.96	)	(71.8	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton	$	4.67	$	24.85	$	(20.18	)	(81.2	)%

OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before tax by $121 million in the three months ended June 30, 2010 compared to a negative $67 million in the three months ended June 30, 2009. The Other Coal segment includes purchased coal activities, closed and idle mine costs, and miscellaneous transactions that are directly related to the coal segment.

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

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 $2 million in the three months ended June 30, 2010 compared to $8 million in the three months ended June 30, 2009. The decrease was due primarily to reduced volumes of purchased coal sold.

Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue is directly offset in freight expense. Freight revenue was $28 million in the three months ended June 30, 2010 compared to $27 million in the three months ended June 30, 2009.

Miscellaneous other income was $12 million in the three months ended June 30, 2010 compared to $30 million in the three months ended June 30, 2009. The $18 million decrease is made up of the following items.

•

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

•

Gain on sales of assets were $2 million in the three months ended June 30, 2010 compared to $8 million in the corresponding prior year period. The change is related to various transactions that occurred throughout both periods, none of which are individually material.

Other coal segment total cost was $167 million in the three months ended June 30, 2010 compared to $132 million in the three months ended June 30, 2009. The increase of $35 million is due to the following items.

•

Closed and idle mine cost of goods sold increased approximately $40 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia has increased. The quantity of material required to reclaim the operation in its present state has increased. As of this time, a specific detailed reclamation plan has not been completely developed and the definitive costs associated with the increased reclamation are not available, however, our current estimates indicate the reclamation liability could equal or exceed $65 million on a present value basis. As a result, approximately $28 million of expense was recognized in the 2010 period to reflect the liability at $65 million. Closed and idled mine costs also increased approximately $28 million related to adjustments made in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 related to other locations mine closure liabilities. At least annually, the engineering studies used as a basis for the mine closing, reclamation and perpetual water treatment costs are reviewed and updated to reflect current estimates. Adjustments to these updated estimates resulted in $28 million of reduced expense in the three months ended June 30, 2009. The engineering estimate updates did not have a significant impact on the three months ended June 30, 2010. These increases were offset, in part, by approximately $9 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in the 2010 period. Additional improvements of $7 million in closed and idle mine costs are due to various transactions that have occurred throughout both periods, none of which were individually material.

•

Litigation expense of $15 million was recognized in the three months ended June 30, 2010 related to a settlement which was reached in June 2010. The litigation was related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. The settlement included $25 million of damages, of which $10 million were expensed in the first quarter 2010 and $15 million was expensed in the second quarter 2010.

•

Litigation expense of $15 million was recognized in the three months ended June 30, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries.

•

Purchased coal consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. These costs were $2 million in the three months ended June 30, 2010 compared to $8 million in the three months ended June 30, 2009.

•

Other expenses related to the coal segment were $1 million higher in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. These increases were related to various transactions that were incurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the three months ended June 30, 2010 compared to the three months ended June 30, 2009:

The Total Gas segment contributed $54 million to earnings before income tax in the three months ended June 30, 2010 compared $53 million in the three months ended June 30, 2009. A detailed variance explanation is described below.


	Three Months Ended June 30, 2010												Difference to Three Months Ended June 30, 2009
	CBM		Conven- tional		Marcellus		Other Gas			Total Gas			CBM			Conven- tional		Marcellus		Other Gas			Total Gas
Sales:
Produced	$	149	$	30	$	10	$	2		$	191		$	5		$	28	$	6	$	2		$	41
Related Party		1		—		—		—			1			1			—		—		—			1

Total Outside Sales		150		30		10		2			192			6			28		6		2			42
Gas Royalty Interest		—		—		—		14			14			—			—		—		5			5
Purchased Gas		—		—		—		2			2			—			—		—		1			1
Other Income		—		—		—		1			1			—			—		—		—			—

Total Revenue and Other Income		150		30		10		19			209			6			28		6		8			48
Lifting		12		5		2		—			19			(1	)		4		2		—			5
Gathering		26		3		2		—			31			4			3		1		—			8
General & Administration		15		4		1		—			20			(2	)		4		—		—			2
Depreciation, Depletion and Amortization		27		15		5		2			49			6			14		3		1			24
Gas Royalty Interest		—		—		—		12			12			—			—		—		6			6
Purchased Gas		—		—		—		1			1			—			—		—		1			1
Exploration and Other Costs		—		—		—		4			4			—			—		—		(2	)		(2	)
Other Corporate		—		—		—		21			21			—			—		—		7			7
Interest Expense		—		—		—		2			2			—			—		—		—			—

Total Cost		80		27		10		42			159			7			25		6		13			51

Earning Before Noncontrolling Interest and Income Tax		70		3		—		(23	)		50			(1	)		3		—		(5	)		(3	)
Noncontrolling Interest		—		—		—		(4	)		(4	)		—			—		—		(4	)		(4	)

Earning Before Income Tax	$	70	$	3	$	—	$	(19	)	$	54		$	(1	)	$	3	$	—	$	(1	)	$	1

COAL BED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed approximately $70 million to the total company earnings before income tax in the three months ended June 30, 2010 compared to $71 million in the three months ended June 30, 2009. The decrease is due to the following items.

CBM Sales revenues increased $6 million from $144 million in the three months ended June 30, 2009 to $150 million in the three months ended June 30, 2010. The increase was primarily due to an 8.6% increase in volumes sold, offset, in part by a 3.4% decrease in average sales price per thousand cubic feet.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		22.8		21.0		1.8		8.6	%
Average CBM Sales price per thousand cubic feet	$	6.57	$	6.80	$	(0.23	)	(3.4	)%

CBM sales volumes increased 1.8 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. Also, the 2009 period CBM volumes were lower by approximately 1.0 billion cubic feet of deferrals related to the idling of the Buchanan Mine throughout most of the 2009 period. The decrease in CBM average sales price is the result of various gas swap transactions throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 13.6 billion cubic feet of our produced CBM gas sales volumes for the three months ended June 30, 2010 at an average price of $8.15 per thousand cubic feet. In the three months ended June 30, 2009, these financial hedges represented approximately 12.5 billion cubic feet at an average price of $8.96 per thousand cubic feet. Although average market prices have increased slightly in the period-to-period comparison, we have sold more hedged volumes at lower average prices in the 2010 period compared to the 2009 period.

CBM lifting costs were $12 million in the three months ended June 30, 2010. This reflects a decrease of approximately $1 million due primarily to a 6.8% decrease in average CBM unit costs offset, in part, by an increase in sales volumes.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		22.8		21.0		1.8		8.6	%
Average CBM lifting costs per thousand cubic feet	$	0.55	$	0.59	$	(0.04	)	(6.8	)%

Average unit costs of CBM were lower in the period-to-period comparison primarily due to the impact of higher volumes on fixed costs and lower idle rig expenses. Idle rig expense decreased due to fewer rigs being idled in the current period. There was one idle rig related to CBM drilling in the 2010 period versus two in the 2009 period.

CBM Gathering costs were $26 million in the three months ended June 30, 2010, or a $4 million increase in the period-to-period comparison. The increase reflects 8.6% of additional volumes and a 4.9% increase in average CBM gathering costs unit costs.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		22.8		21.0		1.8	8.6	%
Average CBM gathering costs per thousand cubic feet	$	1.07	$	1.02	$	0.05	4.9	%

Higher average CBM gathering unit costs are related to higher power charges and additional in-transit charges, offset, in part, by the impact of higher volumes on fixed charges. Power charges have increased in the period-to-period comparison due to higher utility rates being charged in the current year. In-transit charges have increased due to additional capacity of firm transportation being purchased after the 2009 period to assure delivery of additional volumes being produced.

General and administrative costs on the CBM gas segment were $15 million in the three months ended June 30, 2010, which reflects a decrease of $2 million in the period-to-period comparison.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		22.8		21.0		1.8		8.6	%
Average CBM general & administrative costs per thousand cubic feet	$	0.67	$	0.83	$	(0.16	)	(19.3	)%

General and administrative costs attributable to the Total Gas segment have increased approximately $2 million primarily due to additional staffing. With the Dominion Acquisition that closed on April 30, 2010, the majority of the operational support personnel were retained. The additional employees are supporting the ramp up in the gas drilling program.

General and administrative costs attributable to the Total Gas segment are allocated to the individual gas segments based on production. Although total general and administrative costs are higher in the period-to-period comparison, the percentage allocated to CBM is lower based on CBM production volumes to total gas production volumes in the current period. The lower amount allocated to the CBM segment coupled with additional production in the period-to-period comparison lowered unit costs.

Depreciation, depletion and amortization was $27 million in the three months ended June 30, 2010, or $6 million higher than the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		22.8		21.0		1.8	8.6	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet	$	1.17	$	1.03	$	0.14	13.6	%

There was approximately $20 million, or $0.89 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2010. The production portion of depreciation, depletion and amortization was $16 million, or $0.77 per unit-of-production in the three months ended June 30, 2009. The CBM unit-of-production rate increased due to revised rates which are generally calculated at the previous year end using the net book value of assets divided by either proved or proved developed reserves. The addition of the assets and related reserves acquired in the Dominion Acquisition also caused the rate to increase slightly due to the proportion of asset value, which is the purchase price fair value assigned to these assets, to the proved or proved developed reserves acquired. There was approximately $7 million, or $0.28 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the three months ended June 30, 2010. The non production related depreciation, depletion and amortization was $5 million, or $0.26 per thousand cubic feet in the three months ended June 30, 2009. The increase was related to additional gathering assets placed in service after the 2009 period.

CONVENTIONAL GAS SEGMENT

The conventional gas segment contributed approximately $3 million the total company earnings before income tax in the three months ended June 30, 2010. The conventional gas segments contribution to earnings before income tax was insignificant in the three months ended June 30, 2009.

Conventional gas sales revenue was $30 million in the three months ended June 30, 2010, or $28 million higher than the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.4		0.4		6.0		1,500.0	%
Average Conventional Sales price per thousand cubic feet	$	4.71	$	6.83	$	(2.12	)	(31.0	)%

Conventional sales volumes increased 6.0 billion cubic feet in the three months ended June 30, 2010 compared to 2009 primarily due to the Dominion Acquisition which closed on April 30, 2010. Average sales prices of Conventional gas decreased as a result of a eighteen month sales actualization that was recognized in June 2009. The actualization resulted in an additional $0.9 million sales revenue with no corresponding volume adjustment, thus increasing per unit sales price by $2.29 per thousand cubic feet in the 2009 period. Average sales prices excluding this adjustment increased $0.17 per thousand cubic feet reflecting the slight increase in general market prices in the period-to-period comparison.

Lifting costs related to the conventional gas segment were $5 million in the 2010 quarter compared to $1 million in the previous year quarter. The increase is attributable to additional volumes produced in the period and lower average unit costs.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.4		0.4		6.0		1,500.0	%
Average Conventional lifting costs per thousand cubic feet	$	0.71	$	2.34	$	(1.63	)	(69.7	)%

Conventional average lifting unit costs have decreased due to the significant increase in volumes related to the additional production acquired in the Dominion Acquisition which closed on April 30, 2010. In the 2009 period, fixed costs were spread over much lower volumes causing unit cost to be higher.

Gathering costs for the conventional gas segment were $3 million in the three months ended June 30, 2010. These costs were insignificant in the three months ended June 30, 2009. The increase is attributable to additional volumes produced in the period and lower average unit costs as discussed in lifting costs.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.4		0.4		6.0		1,500.0	%
Average Conventional gathering costs per thousand cubic feet	$	0.45	$	0.74	$	(0.29	)	(39.2	)%

Conventional general and administrative costs were $4 million in the 2010 period. These costs were insignificant in the 2009 period.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.4		0.4		6.0	1,500.0	%
Average Conventional general & administrative costs per thousand cubic feet	$	0.69	$	0.48	$	0.21	43.8	%

General and administrative costs attributable to the total gas are allocated to the various gas segments based on production. Conventional production volumes are higher as a percent of total gas production volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the

conventional gas segment in the current period. Total gas segment general and administrative costs have increased in the period-to-period comparison and the portion allocated to the conventional segment has increased causing the average per unit cost to increase. See CBM segment discussion for explanation of total general and administrative costs.

Depreciation, depletion and amortization was $15 million in the three months ended June 30, 2010, or $14 million higher than the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.4		0.4		6.0	1,500.0	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet	$	2.38	$	2.36	$	0.02	0.8	%

There was approximately $13 million, or $2.10 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 in the three months ended June 30, 2010. The production portion of depreciation, depletion and amortization was $1 million, or $2.28 per unit-of-production in the three months ended June 30, 2009. The Conventional unit-of-production decreased due to the addition of the assets and related reserves acquired in the Dominion Acquisition which has a lower rate than the historical conventional well rate. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves. There was approximately $2 million, or $0.28 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, 2010. The non production related depreciation, depletion and amortization was insignificant in the three months ended June 30, 2009, but resulted in approximately $0.08 of average unit costs. The additional assets acquired in the Dominion Acquisition added additional value which is now being depreciated on a straight-line basis.

MARCELLUS GAS SEGMENT

Marcellus gas segment did not significantly impact earnings before income tax for the three months ended June 30, 2010 or 2009.

Marcellus sales revenue was $10 million in the three months ended June 30, 2010 compared to $4 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		2.3		0.8		1.5	187.5	%
Average Marcellus Sales price per thousand cubic feet	$	4.52	$	4.43	$	0.09	2.0	%

Marcellus sales volume increased 1.5 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. At June 30, 2010, there were 26 Marcellus Shale wells in production. At June 30, 2009, there were 15 Marcellus Shale wells in production. Average sales prices for Marcellus gas was up 2% in the period-to-period comparison reflecting the slight increase in general market prices.

Marcellus lifting costs were $2 million in the three months ended June 30, 2010. These costs were insignificant in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		2.3		0.8		1.5	187.5	%
Average Marcellus lifting costs per thousand cubic feet	$	0.64	$	0.20	$	0.44	220.0	%

Average Marcellus lifting cost per unit were higher in the 2010 period compared to the 2009 period. The increase was primarily due to salt water disposal per unit costs and additional road maintenance costs. Higher salt water disposal per unit costs were related to higher volumes of water produced compared to the prior quarter. Higher road maintenance was related to additional number of wells in production in the period-to-period comparison requiring additional miles of road to be maintained.

Gathering costs for Marcellus wells were $2 million in the three months ended June 30, 2010 compared to $1 million in the 2009 period.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		2.3		0.8		1.5		187.5	%
Average Marcellus gathering costs per thousand cubic feet	$	1.05	$	1.54	$	(0.49	)	(31.8	)%

Average gathering costs per unit for Marcellus wells decreased 31.8%, or $0.49 per thousand cubic feet, primarily due to higher volumes which spread fixed cost over more volume.

General and administrative costs attributed to the Marcellus segment were $1 million in both the three months ended June 30, 2010 and 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		2.3		0.8		1.5		187.5	%
Average Marcellus general & administrative costs per thousand cubic feet	$	0.59	$	1.00	$	(0.41	)	(41.0	)%

General and administrative costs attributable to the total gas segment are allocated to the various gas segments based on production. Total general and administrative costs are higher in the period-to-period comparison, as discussed previously in CBM segment. Marcellus volumes are slightly higher as a percent of total gas volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the Marcellus gas segment in the current period. The additional volumes produced by the Marcellus segment have increased significantly more than the increase in the dollars allocated to the segment, therefore lowering the general and administrative average unit costs for the Marcellus segment.

Depreciation, depletion and amortization was $5 million in the three months ended June 30, 2010 compared to $2 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		2.3		0.8		1.5	187.5	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet	$	2.12	$	2.05	$	0.07	3.4	%

There was approximately $5 million, or $1.94 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2010. There was approximately $2 million, or $2.05 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2009. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. Prior to September 30, 2009, depreciation, depletion and amortization rates were not broken down into types of well, instead one pool with all types of wells was used. Therefore, the 2009 rate was a blended rate for all well types. During the quarter ended September 30, 2009, rates

were developed for each type of well. The non production related depreciation, depletion and amortization was insignificant but resulted in an $0.18 per thousand cubic feet per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the three months ended June 30, 2010. The non production related depreciation, depletion and amortization was insignificant in the three months ended June 30, 2009. Due to the low volumes of Marcellus produced in the 2009 period, minimal gathering expenses were allocated to this segment.

OTHER GAS SEGMENT

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

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation were approximately $2 million in the three months ended June 30, 2010. Revenues were insignificant in the 2009 period. Total costs related to these other sales were $3 million in the 2010 period compared to $1 million in the 2009 period. The increase in costs in the period-to-period comparison was primarily attributable to depreciation, depletion and amortization. Higher depreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. The increase in rates were related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. A per unit analysis of the other operating costs in Chattangooga is not meaningful due to the low volumes produced in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales revenue were $14 million in the three months ended June 30, 2010 compared to $9 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		3.4		2.6		0.8	30.8	%
Average Sales Price Per thousand cubic feet	$	4.20	$	3.30	$	0.90	27.3	%

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 $2 million in the three months ended June 30, 2010 compared to $1 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)		0.3		0.3		—	—
Average Sales Price Per thousand cubic feet	$	5.69	$	3.83	$	1.86	48.6	%

Other income was $1 million in both the three months ended June 30, 2010 and 2009.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by CONSOL Energy Gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas costs were $12 million in the three months ended June 30, 2010 compared to $6 million in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		3.4		2.6		0.8	30.8	%
Average Cost Per thousand cubic feet	$	3.42	$	2.47	$	0.95	38.5	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million in the three months ended June 30, 2010. These costs were incidental in the three months ended June 30, 2009.


	For the Three Months Ended June 30,
	2010		2009		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)		0.3		0.2		0.1	50.0	%
Average Cost Price Per thousand cubic feet	$	4.55	$	2.26	$	2.29	101.3	%

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


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Dry hole and lease expiration costs	$	3	$	4	$	(1	)	(25.0	)%
Exploration		1		2		(1	)	(50.0	)%

Total Exploration and Other Costs	$	4	$	6	$	(2	)	(33.3	)%

Other corporate expenses increased $7 million in the current period.


	For the Three Months Ended June 30,
	2010		2009		Variance			Percent Change
Variable interest earnings	$	4	$	—	$	4		100.0	%
Legal fees		3		—		3		100.0	%
Short-term incentive compensation		8		5		3		60.0	%
Bank fees		1		—		1		100.0	%
Stock-based compensation		3		8		(5	)	(62.5	)%
Other		2		1		1		100.0	%

Total Other Corporate Expenses	$	21	$	14	$	7		50.0	%

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 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.

Legal fees are related to expenses for the special committee formed during the CNX Gas take-in transaction.

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

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

Stock-based compensation is lower in the period-to-period comparison primarily due to non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-in transaction. The expense previously recognized for these stock options was reversed on the gas segment. Stock-based compensation is now allocated from CONSOL Energy.

Other corporate expense increased $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 $2 million in both the three months ended June 30, 2010 and 2009. Interest is incurred by the gas segment on the CNX Gas revolving credit facility, a capital lease and a variable interest entity. No significant changes in these components occurred in the period-to-period comparison.

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

OTHER SEGMENT ANALYSIS for the three months ended June 30, 2010 compared to the three months ended June 30, 2009:

The Other segment includes activity from sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment negatively contributed $78 million to total company earnings before income tax in the three months ended June 30, 2010 compared to a negative contribution of $17 in the three months ended June 30, 2009. The other segment also includes total company income tax expense of $25 million in the three months ended June 30, 2010 compared to $54 million in the three months ended June 30, 2009.


	Three Months Ended June 30,
	2010			2009			Variance			Percent Change
Sales—Outside	$	71		$	61		$	10		16.4	%
Other Income		7			8			(1	)	(12.5	)%

Total Revenue		78			69			9		13.0	%
Cost of Goods Sold and Other Charges		149			79			70		88.6	%
Depreciation, Depletion & Amortization		4			5			(1	)	(20.0	)%
Taxes Other Than Income Tax		3			2			1		50.0	%

Total Costs		156			86			70		81.4	%

Earning Before Income Tax		(78	)		(17	)		(61	)	358.8	%
Income Tax		25			54			(29	)	(53.7	)%

Net Income	$	(103	)	$	(71	)	$	(32	)	45.1	%

Industrial supplies:

Total revenue from industrial supplies were $47 million in the three months ended June 30, 2010 compared to $44 million in the three months ended June 30, 2009. The increase was related to additional sales volumes.

Total costs related to industrial supplies were $48 million for the three months ended June 30, 2010 compared to $43 million for the three months ended June 30, 2009. The increase of $5 million was due primarily to additional sales volumes and changes in inventory values.

Transportation operation:

Outside sales related to the transportation operations were $31 million in the three months ended June 30, 2010 compared to $18 million in the three months ended June 30, 2009. The increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Total costs related to the transportation operations were $22 million in the three months ended June 30, 2010 compared to $18 million in the three months ended June 30, 2009. The increase of $4 million was related to the additional thru-put handled by the operation.

Miscellaneous Other:

Additional other income of $7 million was recognized in the other segment in the three months ended June 30, 2009 related to the recognition of previously deferred gain on sale. The deferred gain was recognized in conjunction with the cease use of the previous headquarters.

Other corporate cost in the other segment include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $86 million in the three months ended June 30, 2010 compared to $25 million in the three months ended June 30, 2009. Other corporate costs increased $61 million due to the following.

•

Financing and acquisition fees of $14 million were incurred in the three months ended June 30, 2010 related to the stock and bond issuance that raised in total approximately $4.6 billion dollars. These fees also include costs related to extending and amending the CONSOL Energy revolving credit facility, the acquisition of the Dominion Acquisition, and the CNX Gas take-in transaction.

•

Interest expense was $63 million in the three months ended June 30, 2010 compared to $5 million in the three months ended June 30, 2009. The increase of $58 was primarily related to the additional interest expense owed on the new long-term bonds that were issued in conjunction with the Dominion Acquisition.

•

Various other corporate items improved $11 million primarily due to expenses recognized in conjunction with the cease use of the previous headquarters in the 2009 period and various other transactions that occurred throughout both periods, none of where were individually material.

The effective income tax rate was 26.3% in the three months ended June 30, 2010 compared to 31.4% in the three months ended June 30, 2009. The decrease in the effective tax rate was attributable to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impact the benefit of percentage depletion on the effective tax rate. The current tax rate is also impacted by acquisition and financing fees which are not deductible for tax purposes. See “Note 5-Income Taxes” of the Condensed Consolidated Financial Statements of this Form 10-Q.


	For the Three Months Ended June 30,
	2010			2009			Variance			Percent Change
Total Company Earnings Before Income Taxes	$	96		$	173		$	(77	)	(44.5	)%
Income Tax Expense	$	25		$	54		$	(29	)	(53.7	)%
Effective Income Tax Rate		26.3	%		31.4	%		(5.1	)%

TOTAL COAL SEGMENT ANALYSIS for the six months ended June 30, 2010 compared to the six months ended June 30, 2009:

The coal segment contributed $233 million of earnings before income tax in the 2010 period compared to $336 in the 2009 period. Variances by the individual coal segments are discussed below.


	Six Months Ended June 30, 2010											Difference to Six Months Ended June 30, 2009
	Steam Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam Coal			High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal
Sales:
Produced Coal	$	1,463	$	113	$	275	$	4		$	1,855	$	(131	)	$	113	$	190	$	4		$	176
Purchased Coal		—		—		—		24			24		—			—		—		2			2

Total Outside Sales		1,463		113		275		28			1,879		(131	)		113		190		6			178
Freight Revenue		—		—		—		59			59		—			—		—		1			1
Other Income		4		3		—		24			31		2			3		—		(22	)		(17	)

Total Revenue and Other Income		1,467		116		275		111			1,969		(129	)		116		190		(15	)		162
Costs and expenses:
Total operating costs		872		43		111		167			1,193		50			43		56		2			151
Total provisions		98		5		13		75			191		10			5		4		79			98
Total administrative & other costs		74		3		9		45			131		3			3		3		(1	)		8
Depreciation, depletion and amortization		128		6		9		19			162		—			6		2		(1	)		7

Total Cost and Expenses		1,172		57		142		306			1,677		63			57		65		79			264
Freight Expense		—		—		—		59			59		—			—		—		1			1

Total Cost		1,172		57		142		365			1,736		63			57		65		80			265

Earning Before Income Taxes	$	295	$	59	$	133	$	(254	)	$	233	$	(192	)	$	59	$	125	$	(95	)	$	(103	)

Year-to-Date STEAM COAL SEGMENT

The steam coal segment contributed $295 million to total company earnings before income tax in the six months ended June 30, 2010 compared to $487 million in the six months ended June 30, 2009.

Steam coal revenue was $1,463 million in the six months ended June 30, 2010 compared to $1,594 million in the six months ended June 30, 2009. The $131 million decrease was attributable to the decrease in average sales prices for steam coal and lower steam coal tons sold.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		27.0		27.9		(0.9	)	(3.2	)%
Average Sales Price Per Steam Ton	$	54.13	$	57.23	$	(3.10	)	(5.4	)%

Lower average sales prices for steam coal reflects the roll-off of higher priced contracts signed in the later half of 2008. Steam coal inventory was 2.9 million tons at June 30, 2010. Steam coal sales tons are lower in the period-to-period comparison primarily due to selling approximately 1.5 million tons of this coal on the high volatile (vol) met market at approximately $21.39 per ton higher sales price. Although the sale of these tons lowered the Steam Coal segment revenue by approximately $81 million, total company revenue increased by approximately $32 million. This decrease in Steam tons sold was offset, in part, by the Shoemaker mine

restarting production early in 2010 after being idled throughout the six months ended 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Also, Blacksville #2 increased production in the six months ended June 30, 2010 due to operating throughout the period compared to being idled for a portion of the 2009 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. Operation costs related to the steam coal segment were $872 million in the six months ended June 30, 2010 compared to $822 million in the six months ended June 30, 2009. 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.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		27.0		27.9		(0.9	)	(3.2	)%
Average Operating Costs Per Steam Ton	$	32.26	$	29.53	$	2.73		9.2	%

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

•

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

•

Average operating costs per steam ton sold also increased due to lower tons sold. Fixed costs are allocated over fewer tons, thus increasing unit costs.

•

Labor costs have increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-union mines. Employee counts increased approximately 6% at our active mining operations in order to meet our staffing needs.

•

Health and retirement costs related to the active hourly work force have increased due to higher contributions to the multiemployer 1974 pension trust that is required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America (UMWA) in the six months ended June 30, 2009 to $5.00 per hour in the six months ended June 30, 2010. Contributions to the multiemployer plan are expensed as incurred. These costs have also increased in the period-to-period comparison due to higher medical costs for the active hourly work force.

•

Preparation charges for washing and crushing produced coal to prepare it for sale to customers has also increased due to higher labor charges and additional expenses related to supplies and maintenance used in the process.

•

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

Total provision are made up of the expenses related to the company’s long-term liabilities such as other post employment benefits (OPEB), the salary retirement plan, workers’compensation, long term disability and accretion on the mine closing and related liabilities. With the exception of mine closing and related liabilities

accretion expense, these liabilities are actuarially calculated for the company as a whole. The expenses associated with these costs are allocated to operational units based on active employee counts or active salary dollars. Mine closing and related liabilities accretion is calculated on a mine-by-mine basis. The provision expense attributable to the steam coal segment was $98 million in the six months ended June 30, 2010 compared to $88 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		27.0		27.9		(0.9	)	(3.2	)%
Average Provision Costs Per Steam Ton	$	3.62	$	3.15	$	0.47		14.9	%

Total CONSOL Energy expenses related to our actuarial liabilities were $145 million in the six months ended June 30, 2010 compared to $121 million for the six months ended June 30, 2009. The increase of $24 million is due primarily to changes in the discount rates used at the measurement date, which is December 31, and changes in assumptions which affect the amount amortized into earnings.

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

Total administrative and other costs include selling expenses, general & administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Total administrative and other costs related to the steam coal segment were $74 million in the six months ended June 30, 2010 compared to $71 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		27.0		27.9		(0.9	)	(3.2	)%
Average Selling, Administrative and Other Costs Per Steam Ton	$	2.72	$	2.57	$	0.15		5.8	%

Total company selling, general and administrative costs, excluding commission, are flat in the period-to-period comparison. The percentage of these costs allocated to the steam segment has decreased and the total dollars allocated to the segment have decreased, although not in proportion to the reduction in tons, causing unit costs to increase.

Depreciation, depletion and amortization of $128 million for the steam coal segment was consistent in the period-to-period comparison. The impact on average unit costs was due to reduced tons sold in the period-to-period comparison.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		27.0		27.9		(0.9	)	(3.2	)%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton	$	4.75	$	4.58	$	0.17		3.7	%

Year-to-Date HIGH VOL METALLURGICAL COAL SEGMENT

The high vol metallurgical (met) coal segment contributed $59 million to total company earnings before income tax in the six months ended June 30, 2010. There was no activity in this segment in the prior year. This is a new market that has developed in 2010 is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical markets.

The high vol met coal segment sales revenue was $113 million in the six months ended June 30, 2010. Strength in the met coal market has allowed for the export of Northern Appalachian coal, historically sold domestically in the steam coal market, to crossover to the Brazil and Asia metallurgical coal markets.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		1.5		—		1.5	100.0	%
Average Sales Price Per High Vol Met Ton	$	75.52	$	—	$	75.52	100.0	%

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

Total high vol met coal segment costs were $57 million in the six months ended June 30, 2010. The cost components on a per unit basis are as follows.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		1.5		—		1.5	100.0	%
Average Operating Costs Per High Vol Met Ton	$	28.63	$	—	$	28.63	100.0	%
Average Provision Costs Per High Vol Met Ton	$	3.15	$	—	$	3.15	100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton	$	2.34	$	—	$	2.34	100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton	$	4.13	$	—	$	4.13	100.0	%

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

Year-to-Date LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical (met) coal segment contributed $133 million to the total company earnings before income tax in the six months ended June 30, 2010 compared to $8 million in the six months ended June 30, 2009. The increase is due primarily to the Buchanan Mine being idled for approximately four of the six months ended June 30, 2009. The mine was idled in response to the economic crisis in 2009 that significantly lowered the demand for low volatile coal. This was primarily due to the drop in steel demand.

The low vol met coal segment sales revenue was $275 million in the six months ended June 30, 2010 compared to $85 million in the six months ended June 30, 2009. The increase was due to higher volumes of low vol met coal sold, offset, in part, by a decrease in average sales price in the period-to-period comparison.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		2.2		0.6		1.6		266.7	%
Average Sales Price Per Low Vol Met Ton	$	125.47	$	140.86	$	(15.39	)	(10.9	)%

Average sales prices for low vol met tons have decreased 10.9% mainly due to the roll off of higher priced contracts in the prior year, offset, in part, by improvement in global economic conditions. The period-to-period comparison reflects higher demand for steel and steel related products.

Total costs for the low vol met coal segment were $142 million in the six months ended June 30, 2010 compared to $77 million for the six months ended June 30, 2009. A meaningful comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low vol met coal segment in 2009 as discussed above. The improvements in unit costs are related to operating the Buchanan mine throughout the six months ended June 30, 2010. The 2009 unit costs are not representative of the operating mine due to fix costs being spread over significantly fewer tons. The 2010 period costs are representative of normal costs for this segment.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		2.2		0.6		1.6		266.7	%
Average Operating Costs Per Low Vol Met Ton	$	50.30	$	91.34	$	(41.04	)	(44.9	)%
Average Provision Costs Per Low Vol Met Ton	$	6.11	$	14.55	$	(8.44	)	(58.0	)%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton	$	4.17	$	9.86	$	(5.69	)	(57.7	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton	$	4.18	$	11.83	$	(7.65	)	(64.7	)%

Year-to-Date OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before tax by $254 million in the six months ended June 30, 2010 compared to a negative of $159 million in the six months ended June 30, 2009. The Other Coal segment includes purchased coal activities, closed and idle mine costs, and miscellaneous transactions that are directly related to the coal segment.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The revenues were $24 million in the six months ended June 30, 2010 compared to $22 million in the six months ended June 30, 2009.

Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue is directly offset in freight expense. Freight revenue was $59 million in the six months ended June 30, 2010 compared to $58 million in the six months ended June 30, 2009.

Other income was $24 million in the six months ended June 30, 2010 compared to $46 million in the six months ended June 30, 2009. The $22 million decrease is made up of the following items.

•

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

•

Gain on sales of assets were $1 million in the six months ended June 30, 2010 compared to $10 million in the corresponding prior year period. The change is related to various transactions that occurred throughout both periods, none of which are individually material.

•

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

•

Other miscellaneous income related to the coal segment increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $365 million in the six months ended June 30, 2010 compared to $285 million in the six months ended June 30, 2009. The increase of $80 million is due to the following items.

•

Closed and idle mine cost of goods sold increased approximately $54 million in the six months ended June 30, 2010 compared to the six month ended June 30, 2009. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia has increased approximately $53 million. Changes in mining plans have increased the quantity of material needed to reclaim the disturbed area. As of this time, a specific detailed reclamation plan has not been completely developed and the definitive costs associated with the increased reclamation are not available, however, our current estimates indicate the reclamation liability could equal or exceed $65 million on a present value basis. As a result, $53 million of expense was recognized in the 2010 period. Closed and idled mine costs also increased approximately $25 million related to adjustments made related to other final mine closure costs. At least annually, the engineering studies used as a basis for the mine closing, reclamation and perpetual water treatment costs are reviewed and updated to reflect current estimates. These adjustments resulted in $25 million of reduced expenses in the period-to-period comparison. These increases were offset, in part, by approximately $17 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in the 2010 period. Closed and idle mine costs have also decreased approximately $7 million for various transactions that have occurred throughout both periods, none of which were individually material.

•

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

•

Purchased coal consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. These costs were $24 million in the six months ended June 30, 2010 compared to $21 million in the six months ended June 30, 2009.

•

Litigation expense of $15 million was recognized in the six months ended June 30, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.

•

Other expenses related to the coal segment were $13 million higher in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 related primarily to the legal settlement which included the sale of Jones Fork which resulted in a loss of approximately $12 million in the six months ended June 30, 2010. These increases were related to various transactions that were incurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the six months ended June 30, 2010 compared to the six months ended June 30, 2009:

Earnings before income tax contributed by CONSOL Energy Total Gas segment was $128 million in the six months ended June 30, 2010 compared to $142 in the six months ended June 30, 2009. See analysis below for variance explanations.


	Six Month Ended June 30, 2010												Difference to Six Months Ended June 30, 2009
	CBM		Conven- tional		Marcellus		Other Gas			Total Gas			CBM			Conven- tional		Marcellus		Other Gas			Total Gas
Sales:
Produced	$	310	$	33	$	18	$	3		$	364		$	10		$	28	$	13	$	1		$	52
Related Party		2		—		—		—			2			1			—		—		—			1

Total Outside Sales		312		33		18		3			366			11			28		13		1			53
Gas Royalty Interest		—		—		—		28			28			—			—		—		7			7
Purchased Gas		—		—		—		5			5			—			—		—		2			2
Other Income		—		—		—		1			1			—			—		—		(2	)		(2	)

Total Revenue and Other Income		312		33		18		37			400			11			28		13		8			60
Lifting		25		5		2		—			32			1			4		2		—			7
Gathering		50		3		4		1			58			7			2		2		1			12
General & Administration		30		5		2		—			37			(3	)		4		1		—			2
Depreciation, Depletion and Amortization		54		16		8		3			81			11			14		6		2			33
Gas Royalty Interest		—		—		—		24			24			—			—		—		7			7
Purchased Gas		—		—		—		4			4			—			—		—		2			2
Exploration and Other Costs		—		—		—		9			9			—			—		—		1			1
Other Corporate		—		—		—		27			27			—			—		—		13			13
Interest Expense		—		—		—		4			4			—			—		—		—			—

Total Cost		159		29		16		72			276			16			24		11		26			77

Earning Before Noncontrolling Interest and Income Tax		153		4		2		(35	)		124			(5	)		4		2		(18	)		(17	)
Noncontrolling Interest		—		—		—		(4	)		(4	)		—			—		—		(3	)		(3	)

Earning Before Income Tax	$	153	$	4	$	2	$	(31	)	$	128		$	(5	)	$	4	$	2	$	(15	)	$	(14	)

Year- to-Date CBM GAS SEGMENT:

The CBM segment contributed approximately $153 million to the total company earnings before income tax in the six months ended June 30, 2010 compared to $158 million in the six months ended June 30, 2009. The decrease is due to the following items.

CBM Sales revenues increased $11 million from $301 million in the six months ended June 30, 2009 to $312 million in the six months ended June 30, 2010. The increase was primarily due to a 6.2% increase in volumes sold, offset, in part by a 2.7% decrease in average sales price per thousand cubic feet.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		44.8		42.2		2.6		6.2	%
Average CBM Sales price per thousand cubic feet	$	6.97	$	7.16	$	(0.19	)	(2.7	)%

CBM sales volumes increased 2.6 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. Also, the 2009 period CBM volumes were lower by approximately 1.2 billion cubic feet of deferrals related to the idling of the Buchanan Mine throughout most of the 2009 period. The decrease in CBM average sales price is the result of various gas swap transactions throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 26.6 billion cubic feet of our produced CBM gas sales volumes for the six months ended June 30, 2010 at an average price of $8.45 per thousand cubic feet. In the six months ended June 30, 2009, these financial hedges represented approximately 23.2 billion cubic feet at an average price of $9.37 per thousand cubic feet. Although average market prices have increased slightly in the period-to-period comparison, we have sold more hedge volumes under lower average prices in the 2010 period compared to the 2009 period.

CBM lifting costs were $25 million in the six months ended June 30, 2010. This reflects an increase of approximately $1 million due the increase in sales volumes.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		44.8		42.2		2.6	6.2	%
Average CBM lifting costs per thousand cubic feet	$	0.56	$	0.56	$	—	—

Lifting costs per unit for CBM gas sold have remained consistent in the period-to-period comparison. Salt water disposal costs have improved due to recycling the water produced from our wells to be used in fracing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Also, additional volumes have lowered average lifting costs per unit. Fixed costs incurred are now spread over additional volumes, lowering the per unit costs. These improvements were offset by increased costs for severance taxes. Average market sales prices have increased slightly, causing average unit costs for severance taxes to trend up.

CBM Gathering costs were $50 million in the six months ended June 30, 2010, or a $7 million increase in the period-to-period comparison. The increase reflects additional volumes of 6.2% and a 9.9% increase in average CBM gathering costs unit costs.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		44.8		42.2		2.6	6.2	%
Average CBM gathering costs per thousand cubic feet	$	1.11	$	1.01	$	0.10	9.9	%

General and administrative costs for the CBM gas segment were $30 million in the six months ended June 30, 2010, which reflects a decrease of $3 million in the period-to-period comparison.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		44.8		42.2		2.6		6.2	%
Average CBM general & administrative costs per thousand cubic feet	$	0.68	$	0.78	$	(0.10	)	(12.8	)%

General and administrative costs attributable to the total gas segment have increased approximately $2 million due to additional charges related to higher employee counts. With the Dominion Acquisition the majority

of the operational support personnel were retained. The additional employees are supporting the ramp up in the gas drilling program. These increases in general and administrative costs were offset, in part, by charges from CNX Gas to CONSOL Energy for services provided, prior to the CNX Gas take-in transaction, by gas management employees related to the Dominion Acquisition.

General and administrative costs attributable to the total gas segment are allocated to the individual gas segments based on production. Although total general and administrative costs are higher in the period-to-period comparison, the percentage allocated to CBM is lower based on CBM production volumes to total gas production volumes in the current period.

Depreciation, depletion and amortization was $54 million in the six months ended June 30, 2010, or $11 million higher than the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		44.8		42.2		2.6	6.2	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet	$	1.22	$	1.01	$	0.21	20.8	%

There was approximately $42 million, or $0.95 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the six months ended June 30, 2010. The production portion of depreciation, depletion and amortization was $32 million, or $0.76 per unit-of-production in the six months ended June 30, 2009. The CBM unit-of-production rate increased due to revised rates which are generally calculated using the net book value of assets divided by either proved or proved developed reserves at the previous year end. The in-field drilling program and addition of the assets and related reserves acquired in the Dominion Acquisition caused the rate to increase due to the proportion of asset value to the proved or proved developed reserves. There was approximately $12 million, or $0.27 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 six months ended June 30, 2010. The non production related depreciation, depletion and amortization was $11 million, or $0.25 per thousand cubic feet in the six months ended June 30, 2009. The increase was related to additional gathering assets placed in service after the 2009 period.

Year-to-Date CONVENTIONAL GAS SEGMENT

The conventional gas segment contributed approximately $4 million to total company earnings before income tax in the six months ended June 30, 2010. The conventional gas segment contribution to earnings before tax was insignificant in the six months ended June 30, 2009.

Conventional gas sales revenue was $33 million in the six months ended June 30, 2010, or $28 million higher than the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.8		0.8		6.0		750.0	%
Average Conventional Sales price per thousand cubic feet	$	4.78	$	5.27	$	(0.49	)	(9.3	)%

Conventional sales volumes increased 6.0 billion cubic feet in the six months ended June 30, 2010 compared to 2009 primarily due to the Dominion Acquisition which closed on April 30, 2010. Average sales prices of Conventional gas decreased as a result of an eighteen month sales actualization that was recognized in June 2009. The actualization resulted in an additional $0.9 million sales revenue with no corresponding volume

adjustment, thus increasing the year-to-date per unit sales price by $1.11 per thousand cubic feet. Average sales prices excluding this adjustment increased $0.62 per thousand cubic feet reflecting the general increase in market prices in the period-to-period comparison.

Lifting costs related to the conventional gas segment were $5 million in the current year period compared to $1 million in the previous year period. The increase is attributable to additional volumes produced in the period and lower average unit costs.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.8		0.8		6.0		750.0	%
Average Conventional lifting costs per thousand cubic feet	$	0.79	$	1.39	$	(0.60	)	(43.2	)%

Gathering costs for the conventional gas segment were $3 million in the six months ended June 30, 2010 compared to $1 million in the six months ended June 30, 2009. The increase is attributable to additional volumes produced in the period and lower average unit costs as discussed in lifting costs.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.8		0.8		6.0		750.0	%
Average Conventional gathering costs per thousand cubic feet	$	0.45	$	0.69	$	(0.24	)	(34.8	)%

Conventional general and administrative costs were $5 million in the 2010 period compared to $1 million in the 2009 period.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.8		0.8		6.0	750.0	%
Average Conventional general & administrative costs per thousand cubic feet	$	0.67	$	0.61	$	0.06	9.8	%

General and administrative costs attributable to the total gas are allocated to the various gas segments based on production. Conventional volumes are higher as a percent of total gas volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the conventional gas segment in the current period. See CBM segment discussion for explanation of total general and administrative costs.

Depreciation, depletion and amortization was $16 million in the six months ended June 30, 2010, or $14 million higher than the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		6.8		0.8		6.0	750.0	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet	$	2.39	$	2.23	$	0.16	7.2	%

There was approximately $14 million, or $2.11 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 in the six months ended June 30, 2010. The production portion of depreciation, depletion and amortization was $2 million, or $2.13 per unit-of-production in the six months ended June 30, 2009. The Conventional unit-of-production decreased slightly due to the addition of the assets and related reserves acquired in the Dominion Acquisition which has a slightly lower rate than the historical conventional well rate. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves. There was approximately $2 million, or $0.28 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the six months ended June 30, 2010. The non production related depreciation, depletion and amortization was insignificant in the six months ended June 30, 2009, but resulted in approximately $0.10 of average unit costs. The additional assets acquired in the Dominion Acquisition added additional value which is now being depreciated on a straight-line basis.

Year-to-Date MARCELLUS GAS SEGMENT

Marcellus gas segment contributed $2 million to the total company earnings before income tax in the six months ended June 30, 2010. The Marcellus gas segment’s contribution to the six months ended June 30, 2009 was insignificant.

Marcellus sales revenue was $18 million in the six months ended June 30, 2010 compared to $5 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.7		1.2		2.5	208.3	%
Average Marcellus Sales price per thousand cubic feet	$	4.91	$	4.50	$	0.41	9.1	%

Marcellus sales volume increased 2.5 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. At June 30, 2010, there were 26 Marcellus Shale wells in production. At June 30, 2009, there were 15 Marcellus Shale wells in production. Average sales prices for Marcellus gas were up 9.1% in the period-to-period comparison reflecting the general increase in market prices.

Marcellus lifting costs were $2 million in the six months ended June 30, 2010. These costs were insignificant in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.7		1.2		2.5	208.3	%
Average Marcellus lifting costs per thousand cubic feet	$	0.53	$	0.24	$	0.29	120.8	%

Average Marcellus lifting cost per unit were higher in the 2010 period compared to the 2009 period primarily due to higher salt water disposal per unit costs and additional road maintenance costs. Higher salt water disposal per unit costs were related to higher volumes of water produced compared to the prior year period. Higher road maintenance was related to additional number of wells in production in the period-to-period comparison requiring additional miles of road to be maintained. Road maintenance also increased due to severe winter conditions in the six months ended June 30, 2010 requiring additional maintenance of access roads to be completed.

Gathering costs for Marcellus wells were $4 million in the six months ended June 30, 2010 compared to $2 million in the 2009 period.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.7		1.2		2.5		208.3	%
Average Marcellus gathering costs per thousand cubic feet	$	1.11	$	1.28	$	(0.17	)	(13.3	)%

Average gathering costs per unit for Marcellus wells decreased 13.3%, or $0.17 per thousand cubic feet, primarily due to higher volumes which spread fixed cost over more volumes.

General and administrative costs attributed to the Marcellus segment were $2 million in the six months ended June 30, 2010. These costs were $1 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.7		1.2		2.5		208.3	%
Average Marcellus general & administrative costs per thousand cubic feet	$	0.62	$	1.03	$	(0.41	)	(39.8	)%

General and administrative costs attributable to the total gas segment are allocated to the various gas segments based on production. Total general and administrative costs are higher in the period-to-period comparison, as discussed previously in the CBM segment. Marcellus volumes are slightly higher as a percent of total gas production volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the Marcellus gas segment in the current period. The additional volumes produced by the Marcellus segment have increased significantly more than the increase in the dollars allocated to the segment, therefore lowering the general and administrative average unit costs for the Marcellus segment.

Depreciation, depletion and amortization was $8 million in the six months ended June 30, 2010, compared to $2 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		3.7		1.2		2.5	208.3	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet	$	2.02	$	1.83	$	0.19	10.4	%

There was approximately $7 million, or $1.85 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, 2010. There was approximately $2 million, or $1.74 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, 2009. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. Prior to September 30, 2009, depreciation, depletion and amortization rates were not broken down into types of well, instead one pool with all types of wells was used. Therefore, the 2009 rate was a blended rate for all well types. During the quarter ended September 30, 2009, rates were developed for each type of well. There was approximately $1 million, or $0.17 per thousand cubic feet per unit cost of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight line basis in the six months ended June 30, 2010. The non production related depreciation, depletion and amortization was insignificant in the six months ended June 30, 2009, but resulted in approximately $0.09 per thousand cubic feet. Due to the low volumes of Marcellus produced in the 2009 period, minimal gathering expenses were allocated to this segment.

Year-to-Date OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $3 million in the six months ended June 30, 2010 and $2 million in the six months ended June 30, 2009. Total costs related to these other sales were $4 million in the 2010 period compared to $1 million in the 2009 period. The increase in costs in the period-to-period comparison was primarily attributable to depreciation, depletion and amortization. Higher depreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. The increase in rates was related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. A per unit analysis of the other operating costs in Chattangooga 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’s gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales revenues were $28 million in the six months ended June 30, 2010 compared to $21 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		5.8		4.9		0.9	18.4	%
Average Sales Price Per thousand cubic feet	$	4.88	$	4.38	$	0.50	11.4	%

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 $5 million in the six months ended June 30, 2010 compared to $3 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)		0.8		0.6		0.2	33.3	%
Average Sales Price Per thousand cubic feet	$	5.74	$	4.63	$	1.11	24.0	%

Other income decreased $2 million in the six months ended June 30, 2010 compared to 2009 due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by CONSOL Energy Gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas costs were $24 million in the six months ended June 30, 2010 compared to $17 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		5.8		4.9		0.9	18.4	%
Average Cost Per thousand cubic feet	$	4.07	$	3.51	$	0.56	16.0	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $4 million in the six months ended June 30, 2010 compared to $2 million in the six months ended June 30, 2009.


	For the Six Months Ended June 30,
	2010		2009		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)		0.7		0.5		0.2	40.0	%
Average Cost Price Per thousand cubic feet	$	5.39	$	3.64	$	1.75	48.1	%

Exploration and other costs have increased $1 million in the period-to-period comparison.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Dry hole and lease expiration costs	$	4	$	5	$	(1	)	(20.0	)%
Exploration		5		3		2		66.7	%

Total Exploration and Other Costs	$	9	$	8	$	1		12.5	%

Dry hole and lease expiration costs were $1 million lower due to fewer wells being dry in the 2010 period compared to the 2009 period.

Exploration costs have increased due primarily to additional rental fees on properties where wells have not yet been drilled in order to maintain control of the property. There were more of these payments in the six months ended June 30, 2010 than the six months ended June 30, 2009.

Other corporate expenses increased $13 million in the period-to-period comparison.


	For the Six Months Ended June 30,
	2010		2009		Variance			Percent Change
Short-term incentive compensation	$	12	$	7	$	5		71.4	%
Variable interest earnings		4		1		3		300.0	%
Legal fees		3		—		3		100.0	%
Stock-based compensation		7		5		2		40.0	%
Bank fees		1		—		1		100.0	%
Other		—		1		(1	)	(100.0	)%

Total Other Corporate Expenses	$	27	$	14	$	13		92.9	%

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

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 its purchases of drilling rigs. CONSOL Energy is also the main customer of the third party, and based on analysis, is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact is fully reversed in the noncontrolling interest line discussed below.

Legal fees are related to expenses for the special committee formed during the CNX Gas take-in transaction.

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

Other corporate 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 $4 million in both the six months ended June 30, 2010 and 2009. Interest is incurred by the gas segment on the gas segment revolving credit facility, a capital lease and a variable interest entity. No significant changes in these components occurred in the period-to-period comparison.

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

OTHER SEGMENT ANALYSIS for the six months ended June 30, 2010 compared to the six months ended June 30, 2009:

The Other segment includes activity from sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment negatively contributed $123 million to total company earnings before income tax in the six months ended June 30, 2010 compared to a negative contribution of $20 million in the three months ended June 30, 2009. The other segment also includes total company income tax expense of $60 million for the six months ended June 30, 2010 compared to $134 million for the six months ended June 30, 2009.


	Six Months Ended June 30,
	2010			2009			Variance			Percent Change
Sales—Outside	$	145		$	130		$	15		11.5	%
Other Income		15			12			3		25.0	%

Total Revenue		160			142			18		12.7	%
Cost of Goods Sold and Other Charges		268			147			121		82.3	%
Depreciation, Depletion & Amortization		9			10			(1	)	(10.0	)%
Taxes Other Than Income Tax		6			5			1		20.0	%

Total Costs		283			162			121		74.7	%

Earning Before Income Tax		(123	)		(20	)		(103	)	515.0	%
Income Tax		60			134			(74	)	(55.2	)%

Net Income	$	(183	)	$	(154	)	$	(29	)	18.8	%

Industrial supplies:

Total revenues from the industrial supply operations were $97 million in the six months ended June 30, 2010 compared to $94 million in the six months ended June 30, 2009. The increase of $3 million was due primarily to additional sales volumes.

Total costs related to Fairmont Supply were $98 million for the six months ended June 30, 2010 compared to $87 million for the six months ended June 30, 2009. The increase of $11 million was due primarily to additional sales volumes and changes in inventory values.

Transportation operations:

Total revenue from the transportation operations were $55 million in the six months ended June 30, 2010 compared to $40 million in the six months ended June 30, 2009. The increase of $15 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 $42 million in the six months ended June 30, 2010 compared to $37 million in the six months ended June 30, 2009. The increase of $5 million was related to the additional thru-put tonnage handled by the operation.

Miscellaneous Other:

Other income was $8 million in both the six months ended June 30, 2010 and 2009. The miscellaneous income is related to various transactions that have occurred throughout both periods, none of which are individually material.

Other corporate costs include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $143 million in the six months ended June 30, 2010 compared to $38 million in the six months ended June 30, 2009. Other corporate costs increased $105 million due to the following.

•

Financing and acquisition fees of $61 million were incurred in the six months ended June 30, 2010 related to the equity and debt issuance that raised approximately $4.6 billion dollars. These fees also include costs related to extending and amending the CONSOL Energy revolving credit facility, the Dominion Acquisition and the CNX Gas take-in transaction.

•

Interest expense was $69 million in the six months ended June 30, 2010 compared to $11 million in the six months ended June 30, 2009. The increase of $58 million was primarily related to the additional interest expense owed on the new long-term bonds that were issued in conjunction with the Dominion Acquisition.

•

Various other corporate items decreased $14 million primarily due to expenses recognized in conjunction with 2009 cease use of the previous headquarters. The decrease was also attributable to various transactions that occurred throughout both periods, none of where were individually material.

The effective income tax rate was 25.0% in the six months ended June 30, 2010 and 29.3% in the six months ended June 30, 2009. The effective tax rate is sensitive to the relationship between pre-tax earnings and percentage depletion. The proportion of coal per-tax earnings and gas pre-tax earnings also impact the benefit of percentage depletion on the effective tax rate. The current tax rate is also impacted by acquisition and financing fees which are not deductible for tax purposes. See “Note 5-Income Taxes” of the Condensed Consolidated Financial Statements of this Form 10-Q.


	For the Six Months Ended June 30,
	2010			2009			Variance			Percent Change
Total Company Earnings Before Income Taxes	$	238		$	458		$	(220	)	(48.0	)%
Income Tax Expense	$	60		$	134		$	(74	)	(55.2	)%
Effective Income Tax Rate		25.0	%		29.3	%		(4.3	)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied our working capital requirements and funded our capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CONSOL Energy has refinanced and extended the previous $1.0 billion credit facility to a $1.5 billion credit facility, including borrowings and letters of credit, for a term of four years. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. The facility was expanded to meet the asset development needs of the company. The obligations under the credit agreement continue to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds due March 2012. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 2.00 to 1.00 through 2010, and no less than 2.50 to 1.00 thereafter, measured quarterly. The interest coverage ratio was 8.65 to 1.00 at June 30, 2010. The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00 thereafter, measured quarterly. The leverage ratio was 4.23 to 1.00 at June 30, 2010. The facility also includes a senior secured leverage ratio covenant of no more than 2.50 to 1.00 through 2010, and no more than 2.00 to 1.00 thereafter, measured quarterly. The senior secured leverage ratio was 1.01 to 1.00 at June 30, 2010. 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 the senior unsecured or secured notes. At June 30, 2010, the facility had approximately $292 million drawn and $268 million of letters of credit outstanding, leaving $940 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy completed an equity offering on March 31, 2010 of 44.3 million shares of common stock, which generated net proceeds of approximately $1.8 billion. On April 1, 2010, CONSOL Energy issued $1.5 billion of 8% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020. Covenants in the Notes Indenture limit CONSOL Energy’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company. The equity and bond proceeds were used to complete the Dominion Acquisition for total consideration of approximately $3.476 billion. The acquisition closed on April 30, 2010.

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

On April 23, 2010, CONSOL Energy amended the accounts receivable securitization facility to allow the Company to receive, on a revolving basis up to $200 million of short-term funding and letters of credit. Previously the facility provided up to $165 million. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivables. The facility was expanded to meet the future cash needs of the Company. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper rates plus a charge for administrative services paid to the financial institutions. At June 30, 2010, eligible accounts receivable totaled approximately $200 million. There was no subordinated retained interest at June 30, 2010. Accounts receivable totaling $200 million were reflected as Accounts Receivable—Securitized in Current Assets and Borrowings Under Securitization Facility in Current Liabilities on the consolidated balance sheet at June 30, 2010. There were no letters of credit outstanding against the facility at June 30, 2010.

CNX Gas, a fully consolidated subsidiary of CONSOL Energy, refinanced and extended the existing $200 million credit facility to $700 million, including borrowings and letters of credit, for a term of four years. The facility was expanded to meet the development needs of the company. The obligations under the credit agreement are secured by substantially all of the assets of CNX Gas and its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds due March 2012. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The interest coverage ratio was 100.07 to 1.00 at June 30, 2010. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.23 to 1.00 at June 30, 2010. Covenants in the facility limit our ability to dispose of assets, make investments, pay dividends and merge with another company. At June 30, 2010, the facility had approximately $66 million drawn and $15 million of letters of credit outstanding, leaving $619 million of unused capacity.

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

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

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedge, which exist parallel to the underlying physical transactions. The fair value of these contracts was an asset of $104 million at June 30, 2010. The ineffective portion of these contracts was insignificant to earnings in the six months ended June 30, 2010. Hedge counterparties consists of commercial banks who participate or have been past participants in the revolving credit facility. No issues related to our hedge agreements have been encountered to date.

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

Cash Flows (in millions)


	Six Months Ended June 30
	2010			2009			Change
Cash flows from operating activities	$	506		$	566		$	(60	)
Cash used in investing activities	$	(5,037	)	$	(446	)	$	(4,591	)
Cash provided by (used in) financing activities	$	4,500		$	(150	)	$	4,650

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

•

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

•

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

•

Operating cash flows have decreased due to income taxes paid of $107 million in the six months ended June 30, 2010 compared to $82 million paid in the six months ended June 30, 2009. Income tax payments are higher in the period-to-period comparison primarily due to timing of payments owed.

•

Operating cash flows increased due to coal inventories. Coal inventories decreased 0.4 million tons in the six months ended June 30, 2010 compared to increasing 1.7 million tons in the six months ended June 30, 2009.

Net cash used in investing activities changed 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 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 $82 million to $578 million in 2010 compared to $496 million in 2009. Capital expenditures for coal and other activities increased $107 million due to various projects including the purchase of various coal lands, additional equipment at various mining locations, continued work on longwall face extensions at various locations, and the Buchanan water handling system. Capital expenditures for the gas segment decreased $25 million due to the slow-down in the drilling program as a result of severe winter weather in the six months ended June 30, 2010.

•

Proceeds from the sale of assets were $48 million in 2009 primarily related to the sale leaseback of various mining equipment. Proceeds from the sale of assets in the 2010 were not significant.

Net cash provided by (used in) financing activities changed 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% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.

•

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

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


	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	358,550	$	—	$	—	$	—	$	358,550
Borrowings Under Securitization Facility		200,000		—		—		—		200,000
Purchase Order Firm Commitments		59,238		112,059		22,841		—		194,138
Gas Firm Transportation		33,778		74,586		62,635		326,558		497,557
Long-term Debt		39,141		335,776		5,162		2,770,488		3,150,567
Interest on Long-term Debt		249,137		469,238		448,182		779,328		1,945,885
Capital (Finance) Lease Obligations		7,163		11,456		9,154		37,261		65,034
Interest on Capital (Finance) Lease Obligations		4,536		7,544		6,205		9,451		27,736
Operating Lease Obligations		82,393		131,575		95,706		168,239		477,913
Other Long-term Liabilities (a)		499,259		585,965		589,988		2,502,065		4,177,277

Total Contractual Obligations (b)	$	1,533,195	$	1,728,199	$	1,239,873	$	6,593,390	$	11,094,657

(a)

Long-term liabilities include other post-employment benefits, work-related injuries and illnesses, mine reclamation and closure and other long-term liability costs. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2010 contributions are expected to approximate $64 million.

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

Debt

At June 30, 2010, CONSOL Energy had total long-term debt of $3,215 million outstanding, including the current portion of long-term debt of $46 million. This long-term debt consisted of:

•

An aggregate principal amount of $1.5 billion of 8% senior unsecured notes due in 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 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

•

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

•

An aggregate principal amount of $31 million and $72 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 6.50% per annum and mature in December 2010 and October 2011;

•

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

•

An aggregate principal amount of $12 million on a variable rate note that bears interest at 6.10% at June 30, 2010. This note was incurred by a variable interest entity that is fully consolidated in which CONSOL Energy holds no ownership interest;

•

An aggregate principal amount of $65 million of capital leases with a weighted average interest rate of 6.64% per annum;

At June 30, 2010, CONSOL Energy also had $292 million of aggregate principal amounts of outstanding borrowings and approximately $268 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

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

At June 30, 2010, CNX Gas, a wholly owned subsidiary, had $66 million of aggregate principal amounts of outstanding borrowings and approximately $15 million of letters of credit outstanding under its $700 million secured revolving credit facility.

Total Equity and Dividends

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

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


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

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.40 per share when our leverage ratio covenant exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 4.23 to 1.00 and our availability was approximately $940 million at June 30, 2010. The credit facility does not permit dividend payments in the event of default. There were no such defaults in the six months ended June 30, 2010.

Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at June 30, 2010. The various multi-employer benefit plans are discussed in Note 17-“Other “Employee Benefit Plans” of the 2009 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, 2010. Management believes these items will expire without being funded. See Note 11-“Commitments and Contingent Liabilities” for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Recent Accounting Pronouncements

In April 2010, the Financial Accounting Standards Board issued an update to the Revenue Recognition— Milestone Method Topic of the FASB Accounting Standards Codification which is effective for CONSOL Energy on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010. This update is intended to provide additional application guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research and development transactions. This new guidance does not have a material impact on CONSOL Energy’s financial statements for the current period, nor do we believe that it will have a material impact on the financial statements in future periods.

In April 2010, the Financial Accounting Standards Board issued an update to the Extractive Activities—Oil and Gas Topic of the FASB Accounting Standards Codification which is intended to revise definitions as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. This guidance has been considered during the preparation of the financial statements; however, we believe that the adoption of this new guidance will not have a material impact on CONSOL Energy’s financial statements.

In April 2010, the Financial Accounting Standards Board issued an update to the Compensation—Stock Compensation Topic of the FASB Accounting Standards Codification which is effective for CONSOL Energy beginning December 15, 2010. This update is intended to address the classification of employee share-based payment award with an exercise price denominated in the currency of the market in which the underlying equity security trades. This update affects entities that issue employee share-based payment awards with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades that differs from the functional currency of the employer entity or payroll currency of the employee. As CONSOL Energy does not issue such awards in a currency which differs from the entity’s functional currency, we believe that this new guidance will not have an impact on the financial statements.

Forward-Looking Statements

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

•

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

•

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

•

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

•

reliance on major customers;

•

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

•

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

•

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

•

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

•

our inability to maintain satisfactory labor relations;

•

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

•

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

•

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

•

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

•

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

•

obtaining governmental permits and approvals for our operations;

•

the effects of proposals to regulate greenhouse gas emissions;

•

the effects of government regulation;

•

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

•

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

•

uncertainties in estimating our economically recoverable coal and gas reserves;

•

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

•

increased exposure to employee related long-term liabilities;

•

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

•

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

•

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

•

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

•

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

•

risks in exploring for and producing gas;

•

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

•

the disruption of pipeline systems which deliver our gas;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. CONSOL Energy’s market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

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

For a summary of accounting policies related to derivative instruments, see Note 1 of the Notes to the Consolidated Financial Statements on 2009 Form 10-K.

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

(a)

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

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2010, CONSOL Energy had $3,215 million aggregate principal amount of debt outstanding under fixed-rate instruments and $559 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 $292 million of borrowings outstanding at June 30, 2010. CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 1.67% per annum during the six months ended June 30, 2010. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly decreased net income for the period. CONSOL Energy and CNX Gas, also had outstanding borrowings under their revolving credit facility which bears interest at a variable rate. CNX Gas’ facility had outstanding borrowings of $66 million at June 30, 2010 and bore interest at a weighted average rate of 1.99% per annum during the six months ended June 30, 2010. Due to the level of borrowings against this facility and the low weighted average interest rate in the six months ended June 30, 2010, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income for the period.

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

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, 2010 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

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

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

ITEM 5.

OTHER INFORMATION

Mine Safety and Health Administration Safety Data

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

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

During the three months ended June 30, 2010, neither CONSOL Energy’s mining complexes nor its closed and/or idled mines: (i) were assessed any Mine Act section 110(b)(2) penalties for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., a reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury); (ii) received any Mine Act section 107(a) imminent danger orders to immediately remove miners; (iii) received any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern; or (iv) had any pending legal actions before the Federal Mine Safety and Health Review Commission. In addition, there were no fatalities at CONSOL Energy’s mining complexes or its closed and/or idled mines during the three months ended June 30, 2010.

The table below sets forth by mining complex the total number of citations and/or orders issued during the indicated periods 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, 2010.


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 (in thousands)
Enlow Fork	15	—	—	$	3
Bailey	33	—	—	$	33
McElroy	83	—	2	$	83
Shoemaker	67	—	2	$	4
Loveridge	67	1	5	$	55
Robinson Run	75	—	3	$	75
Blacksville #2	59	1	2	$	16
Buchanan	99	1	4	$	234
AMVEST - Fola Complex	12	—	—		—
Miller Creek Complex	16	—	—		—
Emery	20	—	—	$	80
Other (Keystone Plant)	—	—	—		—

(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 and we believe this presentation will be more useful to investors than providing information based on MSHA identification numbers.

(2)

We have not included currently closed or idled mines in the above table. Our closed and/or idled mines did not receive any of the indicated citations other than Mine 84, which received four Mine Act section 104 significant and substantial citations proposing total assessments of $2 in the quarter ending June 30, 2010.

(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 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.

ITEM 6.

EXHIBITS

Exhibit Index


2.1		Amended and Restated Collateral Trust Agreement dated as of May 7, 2010 among CONSOL Energy Inc., certain of its subsidiaries and Wilmington Trust Company as Corporate Trustee and David A. Vanaskey as Individual Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K filed on May 13, 2010.

2.2		Amended and Restated Pledge Agreement dated as of May 7, 2010 among CONSOL Energy Inc., certain of its subsidiaries and Wilmington Trust Company as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form 8-K filed on May 13, 2010.

2.3		Amended and Restated Security Agreement dated as of May 7, 2010 among CONSOL Energy Inc., certain of its subsidiaries and Wilmington Trust Company as Collateral Trustee, incorporated by reference to Exhibit 2.4 to Form 8-K filed on May 13, 2010.

2.4		First Amendment to Amended and Restated Patent, Trademark and Security Agreement dated as of May 7, 2010 among CONSOL Energy Inc., certain of its subsidiaries and Wilmington Trust Company as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K filed on May 13, 2010.

2.5		Collateral Trust Agreement dated as of May 7, 2010 among CNX Gas Corporation, its wholly-owned subsidiaries and Wilmington Trust Company as Corporate Trustee and David A. Vanaskey as Individual Trustee, incorporated by reference to Exhibit 2.1 to Form 8-K filed by CNX Gas Corporation on May 13, 2010.

2.6		Pledge Agreement dated as of May 7, 2010 among CNX Gas Corporation, its wholly-owned subsidiaries and Wilmington Trust Company as Collateral Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K filed by CNX Gas Corporation on May 13, 2010.

2.7		Security Agreement dated as of May 7, 2010 among CNX Gas Corporation, its wholly-owned subsidiaries and Wilmington Trust Company as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form 8-K filed by CNX Gas Corporation on May 13, 2010.

3.2		Amended and Restated Bylaws of CONSOL Energy Inc., incorporated by reference to Exhibit 3.2 to Form 8-K filed on April 6, 2010.

3.2.1		Amended and Restated Bylaws of CONSOL Energy Inc. (marked to show changes to former bylaws), incorporated by reference to Exhibit 3.2.1 to Form 8-K filed on April 6, 2010.

4.1		Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K filed on April 2, 2010.

4.2		Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8¹/4 % Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K filed on April 2, 2010.

4.3		Registration Rights Agreement dated as of April 1, 2010 among CONSOL Energy Inc. and Bank of America Securities LLC, as representative of the several initial purchasers, incorporated by reference to Exhibit 4.3 to Form 8-K filed on April 2, 2010.

4.4		Supplemental Indenture No. 13 dated as of March 22, 2010, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee.


4.5		Supplemental Indenture No. 14 dated as of April 30, 2010, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee.

10.1		Amended and Restated Credit Agreement dated as of May 7, 2010 among CONSOL Energy Inc., certain of its subsidiaries and the lender parties thereto incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 13, 2010.

10.2		Credit Agreement dated as of May 7, 2010 among CNX Gas Corporation, certain of its wholly-owned subsidiaries and the lender parties thereto, incorporated by reference to Exhibit 10.36 to Form 8-K filed by CNX Gas Corporation on May 13, 2010.

10.3		Form of CONSOL Energy Inc. Employee Nonqualified Performance Stock Option Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K filed by CONSOL Energy Inc. on June 21, 2010.

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, 2010 furnished in XBRL)

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

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 2, 2010



				CONSOL ENERGY INC.

				By:		/S/ J. BRETT HARVEY
						J. Brett Harvey
						Chairman of the Board, President and Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)

				By:		/S/ WILLIAM J. LYONS
						William J. Lyons
						Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial and Accounting Officer)