CNX 10-Q Quarterly Report March 31, 2012

CNX RESOURCES CORP

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10-Q 1 cnx-33112x10q.htm 10-Q CNX-3.31.12-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended March 31, 2012



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of April 18, 2012
Common stock, $0.01 par value		227,545,200

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three months ended March 31, 2012 and 201 1	3
	Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011	4
	Consolidated Balance Sheets at March 31, 2012 and December 31, 201 1	5
	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 201 2	7
	Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 201 1	8
	Notes to Unaudited Consolidated Financial Statements	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	61

ITEM 4.	Controls and Procedures	63

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	64

ITEM 6.	Exhibits	64

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
	March 31,
	2012		2011
Sales—Outside	$	1,311,471	$	1,385,478
Sales—Gas Royalty Interests	12,206		18,835
Sales—Purchased Gas	839		980
Freight—Outside	49,293		36,868
Other Income	52,961		23,216
Total Revenue and Other Income	1,426,770		1,465,377
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	904,041		813,709
Gas Royalty Interests Costs	10,249		16,807
Purchased Gas Costs	517		676
Freight Expense	49,293		36,679
Selling, General and Administrative Expenses	38,999		40,196
Depreciation, Depletion and Amortization	155,347		149,062
Interest Expense	58,120		66,482
Taxes Other Than Income	91,627		90,689
Total Costs	1,308,193		1,214,300
Earnings Before Income Taxes	118,577		251,077
Income Taxes	21,381		58,928
Net Income	$	97,196	$	192,149
Earnings Per Share:
Basic	$	0.43	$	0.85
Dilutive	$	0.42	$	0.84
Weighted Average Number of Common Shares Outstanding:
Basic	227,269,269		226,350,594
Dilutive	230,124,011		228,814,838
Dividends Paid Per Share	$	0.125	$	0.100

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)



	Three Months Ended
	March 31,
	2012			2011
Net Income	$	97,196		$	192,149
Other Comprehensive Income (Loss):
Treasury Rate Lock (Net of tax: $-, $12)	—			(20		)
Actuarially Determined Long-Term Liability Adjustments
Change in Prior Service Cost (Net of tax: ($30,295))	50,276			—
Amortization of Prior Service Cost (Net of tax: $4,552, $4,583)	(7,554		)	(7,365		)
Amortization of Net Loss (Net of tax: ($10,154), ($9,766))	16,851			15,692
Net Increase in the Value of Cash Flow Hedge (Net of tax: ($49,008), ($2,814))	76,076			4,371
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $31,380, $12,615)	(47,941		)	(18,840		)
Other Comprehensive Income (Loss):	87,708			(6,162		)
Comprehensive Income	$	184,904		$	185,987

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	(Unaudited)
	March 31, 2012		December 31, 2011
ASSETS
Current Assets:
Cash and Cash Equivalents	$	287,313	$	375,736
Accounts and Notes Receivable:
Trade	463,258		462,812
Notes Receivables	314,514		314,950
Other Receivables	126,931		105,708
Inventories	284,997		258,335
Deferred Income Taxes	128,904		141,083
Prepaid Expenses	260,818		239,353
Total Current Assets	1,866,735		1,897,977
Property, Plant and Equipment:
Property, Plant and Equipment	14,357,246		14,087,319
Less—Accumulated Depreciation, Depletion and Amortization	4,915,809		4,760,903
Total Property, Plant and Equipment—Net	9,441,437		9,326,416
Other Assets:
Deferred Income Taxes	467,753		507,724
Restricted Cash	22,158		22,148
Investment in Affiliates	200,221		182,036
Notes Receivable	300,382		300,492
Other	296,925		288,907
Total Other Assets	1,287,439		1,301,307
TOTAL ASSETS	$	12,595,611	$	12,525,700

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)



	(Unaudited)
	March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	471,921		$	522,003
Current Portion of Long-Term Debt	20,879			20,691
Accrued Income Taxes	50,313			75,633
Other Accrued Liabilities	856,858			770,070
Total Current Liabilities	1,399,971			1,388,397
Long-Term Debt:
Long-Term Debt	3,122,234			3,122,234
Capital Lease Obligations	54,484			55,189
Total Long-Term Debt	3,176,718			3,177,423
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	2,976,181			3,059,671
Pneumoconiosis Benefits	174,559			173,553
Mine Closing	409,778			406,712
Gas Well Closing	125,557			124,051
Workers’ Compensation	150,377			151,034
Salary Retirement	242,727			269,069
Reclamation	36,148			39,969
Other	129,483			124,936
Total Deferred Credits and Other Liabilities	4,244,810			4,348,995
TOTAL LIABILITIES	8,821,499			8,914,815
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,542,426 Issued and 227,507,671 Outstanding at March 31, 2012; 227,289,426 Issued and 227,056,212 Outstanding at December 31, 2011	2,275			2,273
Capital in Excess of Par Value	2,250,516			2,234,775
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,235,776			2,184,737
Accumulated Other Comprehensive Loss	(713,846		)	(801,554		)
Common Stock in Treasury, at Cost—34,755 Shares at March 31, 2012 and 233,214 Shares at December 31, 2011	(609		)	(9,346		)
Total Stockholders’ Equity	3,774,112			3,610,885
TOTAL LIABILITIES AND EQUITY	$	12,595,611		$	12,525,700

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 Stockholders’ Equity
Balance at December 31, 2011	$	2,273	$	2,234,775		$	2,184,737		$	(801,554	)	$	(9,346	)	$	3,610,885
(Unaudited)
Net Income	—		—			97,196			—			—			97,196
Other Comprehensive Income	—		—			—			87,708			—			87,708
Comprehensive Income	—		—			97,196			87,708			—			184,904
Issuance of Common Stock	2		52			—			—			—			54
Issuance of Treasury Stock	—		—			(17,770		)	—			8,737			(9,033		)
Tax Cost From Stock-Based Compensation	—		(563		)	—			—			—			(563		)
Amortization of Stock-Based Compensation Awards	—		16,252			—			—			—			16,252
Dividends ($0.125 per share)	—		—			(28,387		)	—			—			(28,387		)
Balance at March 31, 2012	$	2,275	$	2,250,516		$	2,235,776		$	(713,846	)	$	(609	)	$	3,774,112

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Three Months Ended
	March 31,
	2012			2011
Operating Activities:
Net Income	$	97,196		$	192,149
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	155,347			149,062
Stock-Based Compensation	16,252			13,446
Gain on Sale of Assets	(19,713		)	(323		)
Amortization of Mineral Leases	1,886			2,468
Deferred Income Taxes	(2,265		)	23,099
Equity in Earnings of Affiliates	(7,935		)	(5,481		)
Changes in Operating Assets:
Accounts and Notes Receivable	(17,990		)	(26,901		)
Inventories	(26,662		)	(29,435		)
Prepaid Expenses	6,231			7,585
Changes in Other Assets	10,837			9,449
Changes in Operating Liabilities:
Accounts Payable	(39,312		)	7,279
Other Operating Liabilities	62,233			75,863
Changes in Other Liabilities	(8,928		)	13,521
Other	2,309			3,463
Net Cash Provided by Operating Activities	229,486			435,244
Investing Activities:
Capital Expenditures	(306,446		)	(254,778		)
Proceeds from Sales of Assets	28,611			300
Distributions, net of (Investments In), From Equity Affiliates	(10,250		)	1,470
Net Cash Used in Investing Activities	(288,085		)	(253,008		)
Financing Activities:
Payments on Short-Term Borrowings	—			(113,500		)
Payments on Miscellaneous Borrowings	(2,330		)	(3,698		)
Payments on Securitization Facility	—			(200,000		)
Proceeds from Issuance of Long-Term Notes	—			250,000
Tax Benefit from Stock-Based Compensation	750			3,306
Dividends Paid	(28,387		)	(22,625		)
Issuance of Common Stock	54			—
Issuance of Treasury Stock	109			3,699
Debt Issuance and Financing Fees	(20		)	(4,517		)
Net Cash Used In Financing Activities	(29,824		)	(87,335		)
Net (Decrease) Increase in Cash and Cash Equivalents	(88,423		)	94,901
Cash and Cash Equivalents at Beginning of Period	375,736			32,794
Cash and Cash Equivalents at End of Period	$	287,313		$	127,695

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2011 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, 2011 included in CONSOL Energy Inc.'s Form 10-K.

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



	Three Months Ended March 31,
	2012	2011
Anti-Dilutive Options	1,574,922	1,157,937
Anti-Dilutive Restricted Stock Units	12,203	—
Anti-Dilutive Performance Share Options	100,350	—
	1,687,475	1,157,937

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



	Three Months Ended March 31,
	2012	2011
Options	11,716	180,396
Restricted Stock Units	458,018	341,141
Performance Share Units	229,730	40,752
	699,464	562,289

The weighted average exercise price per share of the options exercised during the three months ended March 31, 2012 and 2011 was $ 13.81 and $ 20.51 , respectively.

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



	Three Months Ended March 31,
	2012		2011
Net income attributable to CONSOL Energy Inc. shareholders	$	97,196	$	192,149
Weighted average shares of common stock outstanding:
Basic	227,269,269		226,350,594
Effect of stock-based compensation awards	2,854,742		2,464,244
Dilutive	230,124,011		228,814,838
Earnings per share:
Basic	$	0.43	$	0.85
Dilutive	$	0.42	$	0.84

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property, which consisted of 4.3 thousand acres of coal lands and surface rights, for proceeds of $ 13,023 . The gain on the transaction was $ 11,261 and is included in Other Income in the Consolidated Statements of Income.

On October 21, 2011, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of its nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $ 54,254 , which are net of $ 5,719 transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $ 534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gain on the transaction was $ 53,095 and was recognized in the three months ended December 31, 2011.

On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. In September 2011, cash proceeds of $ 485,464 were received related to this transaction, which were net of $ 34,998 transaction fees. Additionally, a note receivable was recognized related to the two additional cash payments to be received on the first and second anniversary of the transaction closing date. The discounted notes receivable of $ 311,754 and $ 296,344 were recorded in Accounts and Notes Receivables—Notes Receivable and Other Assets—Notes Receivable, respectively. In the three months ended December 31, 2011, an additional receivable of $ 16,703 and a payable of $ 980 were recorded for closing adjustments and were included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. The net loss on the transaction was $ 64,142 and was recognized in the three months ended September 30, 2011. As part of the transaction, CNX Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $ 2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry will remain suspended until average natural gas prices are above $4.00 /MMBtu for three consecutive months. Restrictions also include a $ 400,000 annual maximum on Noble's carried cost obligation.

The following unaudited pro forma combined financial statements are based on CONSOL Energy's historical consolidated financial statements and adjusted to give effect to the September 30, 2011 sale of a 50% interest in certain Marcellus Shale assets. The unaudited pro forma results for the period presented below are prepared as if the transaction occurred as of January 1, 2011 and do not include material, non-recurring charges.



	Three Months Ended
	March 31,
	2011
Total Revenue and Other Income	$	1,455,126
Earnings Before Income Taxes	$	247,418
Net Income	$	189,330
Basic Earnings Per Share	$	0.84
Dilutive Earnings Per Share	$	0.83

The pro forma results are not necessarily indicative of what actually would have occurred if the transaction had been completed as of January 1, 2011, nor are they necessarily indicative of future consolidated results.

On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equity method of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $ 119,740 and Noble contributed cash of approximately $ 67,545 . CONE made a cash distribution to CNX Gas in the amount of $ 67,545 . The cash proceeds were recognized as cash inflows of $ 59,870 and $ 7,675 in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, in CONSOL Energy's 2011 third quarter results. The gain on the transaction was $ 7,161 and was recognized in the three months ended September 30, 2011.

On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $ 193,000 . The net gain on the transaction was $ 41,057 was recognized in the three months ended September 30, 2011.

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

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



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
Service cost	$	5,153		$	4,289		$	5,200		$	3,977
Interest cost	9,378			9,078			35,527			42,204
Expected return on plan assets	(11,627		)	(9,630		)	—			—
Amortization of prior service cost (credits)	(408		)	(167		)	(11,599		)	(11,599		)
Recognized net actuarial loss	12,263			9,146			20,345			22,364
Net periodic benefit cost	$	14,759		$	12,716		$	49,473		$	56,946

For the three months ended March 31, 2012 , $ 29,746 was paid to the pension trust for 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 $110,000 to the pension trust in 2012 .

On March 31, 2012, the salaried OPEB plan was remeasured to reflect an announced plan amendment that will reduce medical and prescription drug benefits as of January 1, 2014. The plan amendment calls for a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The amount of contribution is dependent on several

factors. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B or Part D premiums, and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or above at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug benefits. Employees who work or worked in corporate or operational support positions who are under age 50 at December 31, 2013 will receive no medical or prescription drug benefits. The remeasurement reflects the reduction in benefits and the change in discount rate to 4.57% at March 31, 2012 from 4.51% at December 31, 2011. The remeasurement resulted in an $80,570 reduction in the OPEB liability with a corresponding adjustment of $50,275 in other comprehensive income, net of $30,295 in deferred taxes. The change was made to align our corporate and operational support compensation package with our peer group. OPEB expense is expected to be $9,425 lower than the $148,419 that was expected to be recognized over the remaining nine months of 2012.

CONSOL Energy does not expect to contribute to the other postemployment benefit plan in 2012 . We intend to pay benefit claims as they become due. For the three months ended March 31, 2012 , $42,378 of other postemployment benefits have been paid.

For the three months ended March 31, 2011, CONSOL Energy received proceeds of $ 7,781 under the Patient Protection and Affordable Care Act (PPACA) related to reimbursement from the Federal government for retiree health spending. This amount is included as a reduction of benefit and other payments in the reconciliation of changes in benefit obligation. There is no guarantee that additional proceeds will be received under this program.

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

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



	CWP						Workers’ Compensation
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
Service cost	$	1,178		$	1,155		$	3,634		$	4,468
Interest cost	1,991			2,333			1,778			2,060
Amortization of actuarial gain	(4,934		)	(5,478		)	(986		)	(977		)
State administrative fees and insurance bond premiums	—			—			1,910			1,222
Legal and administrative costs	750			750			648			718
Net periodic (benefit) cost	$	(1,015	)	$	(1,240	)	$	6,984		$	7,491

CONSOL Energy does not expect to contribute to the CWP plan in 2012. We intend to pay benefit claims as they become due. For the three months ended March 31, 2012 , $ 2,850 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2012. We intend to pay benefit claims as they become due. For the three months ended March 31, 2012 , $ 9,050 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

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



	For the Three Months Ended March 31,
	2012					2011
	Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	41,502		35.0	%	$	87,877		35.0	%
Excess tax depletion	(26,514		)	(22.4	)	(39,169		)	(15.6	)
Effect of domestic production activities	—			—		(1,916		)	(0.8	)
Net effect of state income taxes	3,510			3.0		8,818			3.5
Other	2,883			2.4		3,318			1.4
Income Tax Expense / Effective Rate	$	21,381		18.0	%	$	58,928		23.5	%

The effective rates for the three months ended March 31, 2012 and 2011 were calculated using the annual effective rate projection on recurring earnings and include tax liabilities related to certain discrete transactions which are described below.

During the three months ended March 31, 2012 , CONSOL Energy reached an agreement with the Internal Revenue Service Appeals Division on its Extraterritorial Income Exclusion refund claim for tax years 2004-2005. As a result of the agreement, the Company reflected $ 983 as a discrete reduction to income tax expense. The discrete transaction was reflected in the Other line of the rate reconciliation.

The total amounts of uncertain tax positions at March 31, 2012 and 2011 were $ 25,570 and $ 65,510 , respectively. If these uncertain tax positions were recognized, approximately $ 3,891 and $ 16,802 , respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the three months ended March 31, 2012 and 2011.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of March 31, 2012 and 2011 , the Company reported an accrued interest liability relating to uncertain tax positions of $ 5,741 and $ 11,895 , respectively. The accrued interest liability includes $ 368 of interest income and $ 1,121 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 , respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of March 31, 2012 and 2011 , CONSOL Energy had no accrued liability for tax penalties.

CONSOL Energy and its subsidiaries file federal income tax returns with the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax determinations by tax authorities for the years before 2008.

NOTE 6—INVENTORIES:

Inventory components consist of the following:



	March 31, 2012		December 31, 2011
Coal	$	125,308	$	105,378
Merchandise for resale	43,130		43,639
Supplies	116,559		109,318
Total Inventories	$	284,997	$	258,335

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 $ 23,093 and $ 22,406 at March 31, 2012 and December 31, 2011 , respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $200,000 . The facility also allows for the issuance of letters of credit against the $200,000 capacity. At March 31, 2012 , there were letters of credit outstanding against the facility of $160,779 . 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. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

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

In accordance with the Transfers and Servicing Topics of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, CONSOL Energy records transactions under the securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral is reported as Accounts Receivable - Securitized and the borrowings are classified as debt in Borrowings under Securitization Facility.

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 $ 419 and $ 724 for the three months ended March 31, 2012 and 2011, respectively. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2017 with the underlying liquidity agreement renewing annually each March.

At March 31, 2012 and December 31, 2011 , eligible accounts receivable totaled $200,000 and $ 192,700 , respectively. There was subordinated retained interest of $39,221 at March 31, 2012 and $192,700 at December 31, 2011 . There were no borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of March 31, 2012 and December 31, 2011 . 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:



	March 31, 2012		December 31, 2011
Coal & Other Plant and Equipment	$	5,301,715	$	5,160,759
Proven Gas Properties	1,542,838		1,542,837
Coal Properties and Surface Lands	1,352,159		1,340,757
Intangible Drilling Cost	1,344,207		1,277,678
Unproven Gas Properties	1,269,083		1,258,027
Gas Gathering Equipment	970,552		963,494
Airshafts	666,334		659,736
Leased Coal Lands	541,577		540,817
Mine Development	474,859		457,179
Gas Wells and Related Equipment	410,245		408,814
Coal Advance Mining Royalties	396,682		393,340
Other Gas Assets	80,459		79,816
Gas Advance Royalties	6,536		4,065
Total Property Plant and Equipment	14,357,246		14,087,319
Less: Accumulated DD&A	4,915,809		4,760,903
Total Net PP&E	$	9,441,437	$	9,326,416

Industry Participation Agreements

As of March 31, 2012, CONSOL Energy had entered into two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for our retained interests. The following table provides information about our industry participation agreements as of March 31, 2012:



Shale Play	Industry Participation Agreement Partner	Industry Participation Agreement Date	Total Drilling Carries		Drilling Carries Billed to Partner		Drilling Carries Remaining
Marcellus	Noble Energy, Inc.	September 30, 2011	$	2,100,000	$	10,204	$	2,089,796
Utica	Hess Ohio Developments, LLC	October 21, 2011	$	534,000	$	3,348	$	530,652

NOTE 9—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's $ 1,500,000 Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1,500,000 of borrowings and letters of credit. CONSOL Energy can request an additional $ 250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio was 5.84 to 1.00 at March 31, 2012 . The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly through March 31, 2013, and no more than 4.50 to 1.00 thereafter. The leverage ratio was 2.10 to 1.00 at March 31, 2012 . The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio was 0.07 to 1.00 at March 31, 2012 . Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. At March 31, 2012 , the $1,500,000 facility had no borrowings outstanding and $ 101,013 of letters of credit outstanding, leaving $ 1,398,987 of capacity available for borrowings and the issuance of letters of credit. The facility had no borrowings outstanding at December 31, 2011 .

CNX Gas Corporation's (CNX Gas) $ 1,000,000 Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000

for borrowings and letters of credit. CNX Gas can request an additional $ 250,000 increase in the aggregate borrowing limit amount. 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 credit facility allows investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in the CONE Gathering Company are unrestricted. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.00 to 1.00 at March 31, 2012 . The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 35.79 to 1.00 at March 31, 2012 . At March 31, 2012 , the $ 1,000,000 facility had no borrowings outstanding and $ 70,203 of letters of credit outstanding, leaving $ 929,797 of capacity available for borrowings and the issuance of letters of credit. The facility had no borrowings outstanding at December 31, 2011 .

NOTE 10—LONG-TERM DEBT:



	March 31, 2012		December 31, 2011
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		250,000
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (6.73% weighted average interest rate for March 31, 2012 and December 31, 2011, respectively)	31,053		31,053
Other long-term note maturing in 2031	75		75
	3,133,993		3,133,993
Less amounts due in one year	11,759		11,759
Long-Term Debt	$	3,122,234	$	3,122,234

Accrued interest related to Long-Term Debt of $ 113,891 and $ 63,577 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at March 31, 2012 and December 31, 2011 , respectively.

NOTE 11—COMMITMENTS AND CONTINGENCIES:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals 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. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amount cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $ 1,562,000 .

The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.

American Electric Corp: On August 8, 2011, the United States Environmental Protection Agency, Region IV, sent Consolidation Coal Company a General Notice and Offer to Negotiate regarding the Ellis Road/American Electric Corp. Superfund Site in Jacksonville, Florida. The General Notice was sent to approximately 180 former customers of American Electric Corp. CONSOL Energy has confirmed that it did business with American Electric Corp. in 1983 and 1984. The General Notice indicated that the Environmental Protection Agency (EPA) has determined that polychlorinated biphenyls (PCBs) and other contaminants in the soils and sediments at and near the site require a removal action. The Offer to Negotiate invited the potentially responsible parties (PRPs) to enter into an Administrative Settlement Agreement and Order on Consent (AOC) to provide for conducting the removal action under the EPA oversight and to reimburse the EPA for its past costs, in the

amount of $ 384 and for its future costs. CONSOL Energy responded to the EPA indicating its willingness to participate in such negotiations, and CONSOL Energy is participating in a group of potentially responsible parties to conduct the removal action. It is likely that the AOC will be executed in the second quarter of 2012. If the AOC is signed by April 30, 2012 the EPA will grant the performing parties a $408 orphan share credit, which will offset the EPA's past costs. The actual scope of the work has yet to be determined, but the current estimate of the total costs of the removal action is in the range of $2,000 to $5,400 , with CONSOL Energy's share of such costs at approximately 8%. CONSOL Energy has established an initial accrual based on its percentage share of the costs at the high end of the range. The liability is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), with respect to the Ward Transformer site in Wake County, North Carolina. 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. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties. The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA's past and future cost, is approximately $ 65,000 . The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $ 11,000 . Also, in September 2008, the EPA notified CONSOL Energy and sixty other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. CONSOL Energy recognized no expense in Cost of Goods Sold and Other charges in the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy's portion of recoveries from settled claims is $ 4,477 . Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at March 31, 2012 is $ 3,483 .

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 7,300 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, 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. Based on over 15 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company's underground longwall mining activities at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently breached the dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resource damages totaling $58,000. In October 2008, the Common Pleas Court ruled that natural resource damages were not recoverable and referred the Commonwealth's claim to the Pennsylvania Department of Environmental Protection (DEP). On February 16, 2010, the DEP issued an interim report, concluding that the alleged damage was subsidence related. The DEP estimated the cost of repair to be approximately $ 20,000 . The Company has appealed the DEP's findings to the Pennsylvania Environmental Hearing Board (PEHB), which will consider the case de novo, meaning without regard to the DEP's decision, as to any finding of causation of damage and/or the amount of damages. 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. A hearing on the merits of the case will not occur until sometime in the spring or summer of 2013. As to the underlying claim, CONSOL Energy 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. If CONSOL Energy is ultimately found to be liable for damages to the dam, we believe the range of loss would be between $ 9,000 and $ 30,000 . There have been settlement discussions and we have established an accrual to cover our estimated settlement liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

C. L. Ritter: On March 1, 2011, the Company was served with a complaint instituted by C. L. Ritter Lumber Company Incorporated against Consolidation Coal Company (CCC), Island Creek Coal Company, (ICCC), CNX Gas Company LLC, subsidiaries of CONSOL Energy Inc., as well as CONSOL Energy itself in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC's Buchanan Mine into nearby void spaces at one of the mines of ICCC. The suit alleges damages of between $34,000 and $430,000 for alleged damage to coal and coalbed methane, as well as breach of contract damages. We have removed the case to federal court and filed a motion to dismiss, largely predicated on the statute of limitations bar. The trial judge ruled that the issue of the applicability of the statute of limitations bar can only be addressed after discovery. There have been settlement discussions and we have established an accrual to cover our estimated settlement liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company LLC et. al. The lawsuit alleges that the plaintiff class consists of oil and gas owners, that the Virginia Supreme Court has decided that coalbed methane (CBM) belongs to the owner of the oil and gas estate, that the Virginia Gas and Oil Act of 1990 unconstitutionally allows force pooling of CBM, that the Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the force pooling orders, and that the Company only relied upon control of the coal estate in force pooling the CBM notwithstanding the Virginia Supreme Court decision holding that if only the coal estate is controlled, the CBM is not thereby controlled. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty, and that CNX Gas need not distribute the net proceeds to class members. The Magistrate Judge recommended against the dismissal of certain other claims, none of which are believed to have any significance. The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. The plaintiffs and CNX Gas have agreed to stay this litigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in Federal court in Virginia styled Addison v. CNX Gas Company LLC. The case involves two primary claims: (i) the plaintiff and similarly situated CNX Gas lessors identified as conflicting claimants during the force pooling process before the Virginia Gas and Oil Board are the owners of the CBM and, accordingly, the owners of the escrowed royalty payments being held by the Commonwealth of Virginia; and (ii) CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiffs seek a declaratory judgment regarding ownership and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking), for force pooling coal owners after the Ratliff decision declared coal owners did not own the CBM; negligent breach of duties as an operator; breach of fiduciary duties; and unjust enrichment. We filed a Motion to Dismiss in this case, and the Magistrate Judge recommended dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. The plaintiffs and CNX Gas Company have agreed to stay this litigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

The following lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly no accrual has been recognized.

South Carolina Gas & Electric Company Arbitration: South Carolina Electric & Gas Company (SCE&G), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company, both wholly owned subsidiaries of CONSOL Energy. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. CONSOL Energy 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 April 30, 2012. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. For that reason, we have not accrued a liability for this claim. If liability is ultimately imposed on the named CONSOL Energy defendants, we believe the range of loss would be between $ 17,000 and $ 29,000 .

CNX Gas Shareholders Litigation: CONSOL Energy has been named as a defendant in five putative class actions brought by alleged shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of

CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the three cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL). All five actions generally allege that CONSOL Energy breached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 per share price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, the actions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys' fees and expenses. The lawsuit will likely go to trial, possibly in 2013. CONSOL Energy believes that these actions are without merit and intends to defend them vigorously. For that reason, we have not accrued a liability for this claim; however, if liability is ultimately imposed, based on the expert reports that have been exchanged by the parties, we believe the range of loss could be up to $ 221,000 .

The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, no accrual has been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues are being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.

Ratliff: On March 22, 2012, the Company was served with four complaints filed on May 31, 2011 which were instituted by four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company, (ICCC), CNX Gas Company LLC, subsidiaries of CONSOL Energy, as well as CONSOL Energy itself in the Circuit Court of Russell County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits each allege damages of between $25,750 and $119,500 for alleged damage to coal and coalbed methane, as well as breach of contract and assumpsit damages. We have removed the cases to federal court and filed a motion to dismiss, largely predicated on the statute of limitations bar. Three similar lawsuits were filed recently, one in federal court and two in the Circuit Court of Buchanan County, Virginia, by other plaintiffs that collectively allege damages of between $100,000 and $622,000. One of the three suits which claimed damages of $22,000 was dismissed in federal court and has been appealed. Another which claimed damages of $312,000 was settled for an amount immaterial to the overall financial position of CONSOL Energy. The Company intends to file a motion to dismiss the remaining case. CCC believes that it had, and continues to have, the right to store water in these void areas. CCC and the other named CONSOL Energy defendants deny all liability and intend to vigorously defend the actions filed against them in connection with the removal and deposit of water from the Buchanan Mine. Consequently, we have not recognized any liability related to these actions.

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

Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas Company. The complaint, as amended, seeks injunctive relief, including removing CNX Gas Company from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summary judgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and briefing will take place before a decision is rendered. CNX Gas Company and CONSOL Energy believe this lawsuit to be without merit and intend to vigorously defend it. Consequently, we

have not recognized any liability related to these actions.

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

Majorsville Storage Field Declaratory Judgment: On March 3, 2011, an attorney sent a letter to CNX Gas Company regarding certain leases that CNX Gas Company obtained from Columbia Gas in Greene County, Pennsylvania involving the Majorsville Storage Field. The letter was written on behalf of three lessors alleging that the leases totaling 525 acres are invalid, and had expired by their terms. The plaintiffs' theory is that the rights of storage and production are severable under the leases. Ignoring the fact that the leases have been used for gas storage, they claim that since there has been no production or development of production, the right to produce gas expired at the end of the primary terms. On June 16, 2011 in the Court of Common Pleas of Greene County, Pennsylvania, the Company filed a declaratory judgment action, seeking to have a court confirm the validity of the leases. We believe that we will prevail in this litigation based on the language of the leases and the current status of the law. Consequently, we have not recognized any liability related to these actions.

The following lawsuit and claims include those for which a loss is remote and accordingly, no accrual has been recognized, although if a non favorable verdict were received the impact could be material.

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

At March 31, 2012 , CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	194,566	$	130,826	$	63,740	$	—	$	—
Environmental	56,994		35,046		21,948		—		—
Other	80,508		43,561		36,947		—		—
Total Letters of Credit	332,068		209,433		122,635		—		—
Surety Bonds:
Employee-Related	204,895		179,515		25,380		—		—
Environmental	447,858		436,545		11,313		—		—
Other	27,729		27,663		65		—		1
Total Surety Bonds	680,482		643,723		36,758		—		1
Guarantees:
Coal	24,802		16,501		3,301		1,000		4,000
Gas	123,418		72,811		19,985		—		30,622
Other	456,389		83,388		137,314		87,975		147,712
Total Guarantees	604,609		172,700		160,600		88,975		182,334
Total Commitments	$	1,617,159	$	1,025,856	$	319,993	$	88,975	$	182,335

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. Coal and Gas financial guarantees have primarily been provided to support various sales contracts. Other guarantees have also been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business.

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheet. As of March 31, 2012 , the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	563,134
1 - 3 years	403,906
3 - 5 years	498,271
More than 5 years	1,639,535
Total Purchase Obligations	$	3,104,846

Costs related to these purchase obligations include:



	Three Months Ended
	March 31,
	2012		2011
Major equipment purchases	$	13,166	$	7,655
Firm transportation expense	15,045		12,818
Gas drilling obligations	29,576		25,818
Other	298		101
Total costs related to purchase obligations	$	58,085	$	46,392

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. The fair value of CONSOL Energy's derivatives (natural gas price swaps) are based on intra-bank pricing models which utilize inputs that are either readily available in the public market, such as natural gas forward curves, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

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

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

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodity. As of March 31, 2012 , the total notional amount of the Company’s outstanding natural gas swap contracts was 160.0 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2015 and meet the criteria for cash flow hedge accounting. During the next twelve months, $ 110,024 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings, as a result of the settlement of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The fair value at March 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $ 297,708 and a liability of $ 1,505 . The total asset is comprised of $ 181,072 and $ 116,636 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is included in Other Liabilities on the Consolidated Balance Sheets.

The fair value at December 31, 2011 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $ 251,277 . The total asset is comprised of $ 153,376 and $ 97,901 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets.

The effect of derivative instruments in cash flow hedging relationships on the Consolidated Statements of Income and the Consolidated Statements of Stockholders' Equity were as follows:



	Three Months Ended March 31,
	2012			2011
Natural Gas Price Swaps
Gain recognized in Accumulated OCI	$	76,076		$	4,371
Gain reclassified from Accumulated OCI into Outside Sales	$	47,941		$	18,840
Loss recognized in Outside Sales for ineffectiveness	$	(835	)	$	(108	)

NOTE 13—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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



	Fair Value Measurements at March 31, 2012						Fair Value Measurements at December 31, 2011
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	296,203	$	—	$	—	$	251,277	$	—

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

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

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

Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

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



	March 31, 2012						December 31, 2011
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	287,313		$	287,313		$	375,736		$	375,736
Restricted cash	$	22,158		$	22,158		$	22,148		$	22,148
Long-term debt	$	(3,133,993	)	$	(3,270,880	)	$	(3,133,993	)	$	(3,422,452	)

NOTE 14—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal division are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three months ended March 31, 2012 , the Thermal aggregated segment includes the following mines: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the three months ended March 31, 2012 , the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the three months ended March 31, 2012 , the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge and Robinson Run coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to each individual mine. The principal activity of the Gas division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as various other activities assigned to the Gas division but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services, general and administrative activities and other business activities. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (coal, gas and other) and are not allocated between each individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

Industry segment results for the three months ended March 31, 2012 are:



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	812,053	$	172,740	$	60,568	$	8,955		$	1,054,316	$	99,535	$	23,791	$	34,373		$	2,504		$	160,203	$	96,952	$	—		$	1,311,471	(A)
Sales—purchased gas	—		—		—		—			—		—		—		—			839			839		—		—			839
Sales—gas royalty interests	—		—		—		—			—		—		—		—			12,206			12,206		—		—			12,206
Freight—outside	—		—		—		49,293			49,293		—		—		—			—			—		—		—			49,293
Intersegment transfers	—		—		—		—			—		—		—		—			466			466		37,209		(37,675		)	—
Total Sales and Freight	$	812,053	$	172,740	$	60,568	$	58,248		$	1,103,609	$	99,535	$	23,791	$	34,373		$	16,015		$	173,714	$	134,161	$	(37,675	)	$	1,373,809
Earnings (Loss) Before Income Taxes	$	128,855	$	79,361	$	15,611	$	(61,357	)	$	162,470	$	36,390	$	3,251	$	(3,722	)	$	(23,419	)	$	12,500	$	4,083	$	(60,476	)	$	118,577	(B)
Segment assets										$	5,360,577											$	6,110,585	$	358,746	$	765,703		$	12,595,611	(C)
Depreciation, depletion and amortization										$	100,762											$	48,803	$	5,782	$	—		$	155,347
Capital expenditures										$	194,429											$	98,455	$	13,562	$	—		$	306,446


(A)	Included in the Coal segment are sales of $144,155 to First Energy and $138,341 to Xcoal Energy & Resources each comprising over 10% of sales.


(B)	Includes equity in earnings of unconsolidated affiliates of $ 4,807 , $ 1,944 and $ 1,184 for Coal, Gas and All Other, respectively.


(C)	Includes investments in unconsolidated equity affiliates of $ 39,373 , $ 108,858 and $ 51,990 for Coal, Gas and All Other, respectively.

Industry segment results for the three months ended March 31, 2011 are:



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	801,952	$	236,895	$	78,233	$	13,364		$	1,130,444	$	113,774	$	21,042	$	38,745		$	2,648		$	176,209	$	78,825		$	—		$	1,385,478
Sales—purchased gas	—		—		—		—			—		—		—		—			980			980		—			—			980
Sales—gas royalty interests	—		—		—		—			—		—		—		—			18,835			18,835		—			—			18,835
Freight—outside	—		—		—		36,868			36,868		—		—		—			—			—		—			—			36,868
Intersegment transfers	—		—		—		—			—		—		—		—			993			993		53,396			(54,389		)	—
Total Sales and Freight	$	801,952	$	236,895	$	78,233	$	50,232		$	1,167,312	$	113,774	$	21,042	$	38,745		$	23,456		$	197,017	$	132,221		$	(54,389	)	$	1,442,161
Earnings (Loss) Before Income Taxes	$	194,044	$	142,594	$	40,893	$	(78,839	)	$	298,692	$	50,003	$	8,503	$	(2,750	)	$	(31,580	)	$	24,176	$	(1,849	)	$	(69,942	)	$	251,077	(D)
Segment assets										$	5,092,682											$	5,966,395	$	341,613		$	823,051		$	12,223,741	(E)
Depreciation, depletion and amortization										$	95,081											$	49,664	$	4,317		$	—		$	149,062
Capital expenditures										$	100,530											$	150,638	$	3,610		$	—		$	254,778


(D)	Includes equity in earnings of unconsolidated affiliates of $ 4,462 , $484 and $ 535 for Coal, Gas and All Other, respectively.

(E) Includes investments in unconsolidated equity affiliates of $ 24,455 , $ 24,053 and $ 49,012 for Coal, Gas and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended March 31,
	2012			2011
Segment Earnings Before Income Taxes for total reportable business segments	$	174,970		$	322,868
Segment Earnings Before Income Taxes for all other businesses	4,083			(1,849		)
Interest income (expense), net and other non-operating activity (F)	(60,042		)	(69,286		)
Evaluation fees for non-core asset dispositions (F)	(434		)	(656		)
Earnings Before Income Taxes	$	118,577		$	251,077



Total Assets:	March, 31
Total Assets:	2012		2011
Segment assets for total reportable business segments	$	11,471,162	$	11,059,077
Segment assets for all other businesses	358,746		341,613
Items excluded from segment assets:
Cash and other investments (F)	121,807		126,613
Recoverable income taxes	—		5,031
Deferred tax assets	596,657		636,636
Bond issuance costs	47,239		54,771
Total Consolidated Assets	$	12,595,611	$	12,223,741

_________________________

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

NOTE 15—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000 , 8.000% per annum notes due April 1, 2017 , the $1,250,000 , 8.250% per annum notes due April 1, 2020 , and the $250,000 , 6.375% per annum notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the three months ended March 31, 2012 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	160,669	$	1,082,288	$	69,022	$	(508	)	$	1,311,471
Sales—Gas Royalty Interests	—			12,206		—		—		—			12,206
Sales—Purchased Gas	—			839		—		—		—			839
Freight—Outside	—			—		49,293		—		—			49,293
Other Income (including equity earnings)	170,023			16,305		29,703		5,957		(169,027		)	52,961
Total Revenue and Other Income	170,023			190,019		1,161,284		74,979		(169,535		)	1,426,770
Cost of Goods Sold and Other Operating Charges	49,180			98,701		682,700		66,416		7,044			904,041
Gas Royalty Interests’ Costs	—			10,255		—		—		(6		)	10,249
Purchased Gas Costs	—			517		—		—		—			517
Related Party Activity	6,015			—		1,258		502		(7,775		)	—
Freight Expense	—			—		49,293		—		—			49,293
Selling, General and Administrative Expense	—			9,924		28,628		447		—			38,999
Depreciation, Depletion and Amortization	3,919			48,803		102,102		523		—			155,347
Interest Expense	54,762			1,218		2,229		11		(100		)	58,120
Taxes Other Than Income	2,674			8,200		79,933		820		—			91,627
Total Costs	116,550			177,618		946,143		68,719		(837		)	1,308,193
Earnings (Loss) Before Income Taxes	53,473			12,401		215,141		6,260		(168,698		)	118,577
Income Tax Expense (Benefit)	(43,723		)	4,947		57,789		2,368		—			21,381
Net Income (Loss)	$	97,196		$	7,454	$	157,352	$	3,892	$	(168,698	)	$	97,196

Balance Sheet at March 31, 2012 (unaudited):



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	119,562	$	166,205		$	957		$	589	$	—		$	287,313
Accounts and Notes Receivable:
Trade	—		41,694			423			421,141		—			463,258
Notes Receivable	2,233		311,754			527			—		—			314,514
Other	2,670		109,101			10,440			4,720		—			126,931
Inventories	—		10,508			231,359			43,130		—			284,997
Deferred Income Taxes	190,377		(61,473		)	—			—		—			128,904
Prepaid Expenses	20,409		186,888			51,900			1,621		—			260,818
Total Current Assets	335,251		764,677			295,606			471,201		—			1,866,735
Property, Plant and Equipment:
Property, Plant and Equipment	204,057		5,577,282			8,551,640			24,267		—			14,357,246
Less-Accumulated Depreciation, Depletion and Amortization	113,848		825,783			3,958,974			17,204		—			4,915,809
Property, Plant and Equipment-Net	90,209		4,751,499			4,592,666			7,063		—			9,441,437
Other Assets:
Deferred Income Taxes	935,069		(467,316		)	—			—		—			467,753
Restricted Cash	22,158		—			—			—		—			22,158
Investment in Affiliates	9,464,098		108,858			720,339			—		(10,093,074		)	200,221
Notes Receivable	4,038		296,344			—			—		—			300,382
Other	123,720		127,733			35,475			9,997		—			296,925
Total Other Assets	10,549,083		65,619			755,814			9,997		(10,093,074		)	1,287,439
Total Assets	$	10,974,543	$	5,581,795		$	5,644,086		$	488,261	$	(10,093,074	)	$	12,595,611
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	133,860	$	185,616		$	140,393		$	12,052	$	—		$	471,921
Accounts Payable (Recoverable)—Related Parties	3,026,857		15,655			(3,368,808		)	326,296		—			—
Current Portion Long-Term Debt	824		5,848			13,506			701		—			20,879
Accrued Income Taxes	49,826		487			—			—		—			50,313
Other Accrued Liabilities	645,803		62,128			136,219			12,708		—			856,858
Total Current Liabilities	3,857,170		269,734			(3,078,690		)	351,757		—			1,399,971
Long-Term Debt:	3,001,170		49,813			124,566			1,169					3,176,718
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			2,976,181			—		—			2,976,181
Pneumoconiosis Benefits	—		—			174,559			—		—			174,559
Mine Closing	—		—			409,778			—		—			409,778
Gas Well Closing	—		63,004			62,553			—		—			125,557
Workers’ Compensation	—		—			150,113			264		—			150,377
Salary Retirement	242,727		—			—			—		—			242,727
Reclamation	—		—			36,148			—		—			36,148
Other	99,364		20,727			9,392			—		—			129,483
Total Deferred Credits and Other Liabilities	342,091		83,731			3,818,724			264		—			4,244,810
Total Stockholders’ Equity	3,774,112		5,178,517			4,779,486			135,071		(10,093,074		)	3,774,112
Total Liabilities and Stockholders’ Equity	$	10,974,543	$	5,581,795		$	5,644,086		$	488,261	$	(10,093,074	)	$	12,595,611

Income Statement for the three months ended March 31, 2011 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	177,202	$	1,155,350		$	54,096	$	(1,170	)	$	1,385,478
Sales—Gas Royalty Interests	—			18,835		—			—		—			18,835
Sales—Purchased Gas	—			980		—			—		—			980
Freight—Outside	—			—		36,868			—		—			36,868
Other Income (including equity earnings)	246,864			1,680		11,421			9,241		(245,990		)	23,216
Total Revenue and Other Income	246,864			198,697		1,203,639			63,337		(247,160		)	1,465,377
Cost of Goods Sold and Other Operating Charges	28,976			87,612		628,960			53,987		14,174			813,709
Gas Royalty Interests’ Costs	—			16,821		—			—		(14		)	16,807
Purchased Gas Costs	—			676		—			—		—			676
Related Party Activity	(3,240		)	—		(1,741		)	466		4,515			—
Freight Expense	—			—		36,679			—		—			36,679
Selling, General and Administrative Expense	—			9,356		30,557			283		—			40,196
Depreciation, Depletion and Amortization	2,361			49,664		96,408			629		—			149,062
Interest Expense	61,142			2,680		2,742			13		(95		)	66,482
Taxes Other Than Income	1,503			7,807		80,514			865		—			90,689
Total Costs	90,742			174,616		874,119			56,243		18,580			1,214,300
Earnings (Loss) Before Income Taxes	156,122			24,081		329,520			7,094		(265,740		)	251,077
Income Tax Expense (Benefit)	(36,027		)	9,435		82,837			2,683		—			58,928
Net Income (Loss)	$	192,149		$	14,646	$	246,683		$	4,411	$	(265,740	)	$	192,149

Balance Sheet at December 31, 2011:



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	37,342	$	336,727		$	1,269		$	398	$	—		$	375,736
Accounts and Notes Receivable:
Trade	—		63,299			(5,081		)	404,594		—			462,812
Notes Receivable	2,669		311,754			527			—		—			314,950
Other	2,913		91,582			7,458			3,755		—			105,708
Inventories	—		8,600			206,096			43,639		—			258,335
Deferred Income Taxes	191,689		(50,606		)	—			—		—			141,083
Prepaid Expenses	28,470		159,900			49,224			1,759		—			239,353
Total Current Assets	263,083		921,256			259,493			454,145		—			1,897,977
Property, Plant and Equipment:
Property, Plant and Equipment	198,004		5,488,094			8,376,831			24,390		—			14,087,319
Less-Accumulated Depreciation, Depletion and Amortization	109,924		778,716			3,855,323			16,940		—			4,760,903
Property, Plant and Equipment-Net	88,080		4,709,378			4,521,508			7,450		—			9,326,416
Other Assets:
Deferred Income Taxes	963,332		(455,608		)	—			—		—			507,724
Restricted Cash	22,148		—			—			—		—			22,148
Investment in Affiliates	9,126,453		96,914			760,548			—		(9,801,879		)	182,036
Notes Receivable	4,148		296,344			—			—		—			300,492
Other	116,624		110,128			52,009			10,146		—			288,907
Total Other Assets	10,232,705		47,778			812,557			10,146		(9,801,879		)	1,301,307
Total Assets	$	10,583,868	$	5,678,412		$	5,593,558		$	471,741	$	(9,801,879	)	$	12,525,700
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	140,823	$	206,072		$	164,521		$	10,587	$	—		$	522,003
Accounts Payable (Recoverable)-Related Parties	2,900,546		9,431			(3,228,229		)	318,252		—			—
Current Portion of Long-Term Debt	805		5,587			13,543			756		—			20,691
Accrued Income Taxes	68,819		6,814			—			—		—			75,633
Other Accrued Liabilities	493,450		58,401			206,649			11,570		—			770,070
Total Current Liabilities	3,604,443		286,305			(2,843,516		)	341,165		—			1,388,397
Long-Term Debt:	3,001,092		50,326			124,674			1,331		—			3,177,423
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		—			3,059,671			—		—			3,059,671
Pneumoconiosis Benefits	—		—			173,553			—		—			173,553
Mine Closing	—		—			406,712			—		—			406,712
Gas Well Closing	—		61,954			62,097			—		—			124,051
Workers’ Compensation	—		—			150,786			248		—			151,034
Salary Retirement	269,069		—			—			—		—			269,069
Reclamation	—		—			39,969			—		—			39,969
Other	98,379		16,899			9,658			—		—			124,936
Total Deferred Credits and Other Liabilities	367,448		78,853			3,902,446			248		—			4,348,995
Total Stockholders’ Equity	3,610,885		5,262,928			4,409,954			128,997		(9,801,879		)	3,610,885
Total Liabilities and Stockholders’ Equity	$	10,583,868	$	5,678,412		$	5,593,558		$	471,741	$	(9,801,879	)	$	12,525,700

Cash Flow for the Three Months Ended March 31, 2012 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	123,513		$	54,417		$	51,118		$	438		$	—	$	229,486
Cash Flows from Investing Activities:
Capital Expenditures	$	(13,562	)	$	(98,455	)	$	(194,429	)	$	—		$	—	$	(306,446	)
Investment in Equity Affiliates	—			(13,500		)	(250		)	—			—		(13,750		)
Distributions from Equity Affiliates	—			3,500			—			—			—		3,500
Other Investing Activities	—			4,360			24,249			2			—		28,611
Net Cash Used in Investing Activities	$	(13,562	)	$	(104,095	)	$	(170,430	)	$	2		$	—	$	(288,085	)
Cash Flows from Financing Activities:
Dividends Received (Paid)	$	91,613		$	(120,000	)				$	—		$	—	$	(28,387	)
Other Financing Activities	657			(844		)	(1,000		)	(250		)	—		(1,437		)
Net Cash Provided by (Used in) Financing Activities	$	92,270		$	(120,844	)	$	(1,000	)	$	(250	)	$	—	$	(29,824	)

Cash Flow for the Three Months Ended March 31, 2011 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	238,347		$	97,033		$	98,935		$	929		$	—	$	435,244
Cash Flows from Investing Activities:
Capital Expenditures	$	(3,613	)	$	(150,638	)	$	(100,527	)	$	—		$	—	$	(254,778	)
Distributions from Equity Affiliates	—			—			1,470			—			—		1,470
Other Investing Activities	10			40			245			5			—		300
Net Cash Used in Investing Activities	$	(3,603	)	$	(150,598	)	$	(98,812	)	$	5		$	—	$	(253,008	)
Cash Flows from Financing Activities:
Dividends Paid	$	(22,625	)	$	—		$	—		$	—		$	—	$	(22,625	)
(Payments on) Proceeds from Short-Term Borrowings	(155,000		)	41,500			—			—			—		(113,500		)
Payments on Securitization Facility	(200,000		)	—			—			—			—		(200,000		)
Proceeds from Long-Term Notes	250,000			—			—			—			—		250,000
Debt Issuance and Financing Fees	(4,517		)				—			—			—		(4,517		)
Other Financing Activities	6,781			(2,759		)	(516		)	(199		)	—		3,307
Net Cash Provided by (Used in) Financing Activities	$	(125,361	)	$	38,741		$	(516	)	$	(199	)	$	—	$	(87,335	)

Statement of Comprehensive Income for the Three Months Ended March 31, 2012 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Net Income	$	97,196		$	7,454		$	157,352		$	3,892	$	(168,698	)	$	97,196
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments
Change in Prior Service Cost (Net of tax: ($30,295))	50,276			—			50,276			—		(50,276		)	50,276
Amortization of Prior Service Cost (Net of tax:$4,552)	(7,554		)	—			(7,300		)	—		7,300			(7,554		)
Amortization of Net Loss (Net of tax:($10,154))	16,851			—			9,199			—		(9,199		)	16,851
Net Increase in the Value of Cash Flow Hedge (Net of Tax: ($49,008))	76,076			76,076			—			—		(76,076		)	76,076
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax:$31,380)	(47,941		)	(47,941		)	—			—		47,941			(47,941		)
Other Comprehensive Income (Loss):	87,708			28,135			52,175			—		(80,310		)	87,708
Comprehensive Income	$	184,904		$	35,589		$	209,527		$	3,892	$	(249,008	)	$	184,904

Statement of Comprehensive Income for the Three Months Ended March 31, 2011 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Net Income	$	192,149		$	14,646		$	246,683		$	4,411	$	(265,740	)	$	192,149
Other Comprehensive Income (Loss):
Treasury Rate Lock (Net of tax:$12)	(20		)	—			—			—		—			(20		)
Actuarially Determined Long-Term Liability Adjustments
Amortization of Prior Service Cost (Net of tax:$4,583)	(7,365		)	—			(7,262		)	—		7,262			(7,365		)
Amortization of Net Loss (Net of tax:($9,766))	15,692			—			10,055			—		(10,055		)	15,692
Net Increase in the Value of Cash Flow Hedge (Net of Tax: ($2,814))	4,371			4,371			—			—		(4,371		)	4,371
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax:$12,615)	(18,840		)	(18,840		)	—			—		18,840			(18,840		)
Other Comprehensive Income (Loss):	(6,162		)	(14,469		)	2,793			—		11,676			(6,162		)
Comprehensive Income	$	185,987		$	177		$	249,476		$	4,411	$	(254,064	)	$	185,987

NOTE 16—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the three months ended March 31, 2012, CONE Gathering LLC (CONE), a 50% owned affiliate, provided CNX Gas Company LLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $3,462 , which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of March 31, 2012 and December 31, 2011, CONSOL Energy and CNX Gas had a net receivable of $ 29,872 and $ 8,966 , respectively, which were comprised of the following items:



	March 31,			December 31,
	2012			2011			Location on Balance Sheet
CONE Gathering Capital Reimbursement	$	29,754		$	8,042		Accounts Receivable–Other
Reimbursement for CONE Expenses	205			2,009			Accounts Receivable–Other
Reimbursement for Services Provided to CONE	663			414			Accounts Receivable–Other
CONE Gathering Fee Payable	(750		)	(1,499		)	Accounts Payable
Net Receivable due from CONE	$	29,872		$	8,966


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

General

The domestic coal and natural gas industries faced challenges during the first quarter of 2012 amid a warm winter that reduced electricity and seasonal gas demand. The confluence of diminished demand and abundant natural gas supply contributed to lower coal and natural gas prices and increased inventories. Although international thermal coal prices have declined slightly and metallurgical coal prices have declined off recent highs, we believe that longer-term demand fundamentals remain sound.

Warmer temperatures coupled with lower electricity demand reduced domestic thermal coal consumption during the first quarter. Lower natural gas prices made gas-fired generation more competitive, reducing the demand for coal-fired generation. Preliminary estimates are that coal-fired generation supplied 39% of the U.S electric power sector during the first quarter versus 46% in 2011. As a result, utility stockpiles were up an estimated 25% across the nation versus the first quarter of 2011. Stockpiles grew more significantly in CONSOL Energy's traditional Mid-Atlantic and Southeast markets.

Long-term domestic outlook for coal declined slightly during the first quarter as new U.S. Environmental Protection Agency (EPA) power plant rules are likely to limit future demand. Utilities have begun to retire older, less cost effective units rather than invest in emission controls to bring these units into compliance. Despite the challenges facing domestic thermal coal demand, international demand and pricing have more favorable outlooks. In Europe, the effects of decreased nuclear production, the reduction in renewable subsidies and the phase-out of subsidized European mining has the potential to increase coal demand.

Metallurgical coal supply and demand was closer into balance than last year, thereby reducing settlement prices below 2011 levels. However, there are recent indications that Australian metallurgical coal producers are again struggling with weather induced operational disruptions and new labor issues. The affected mining regions represent a large percentage of global supply and we believe this may impact global pricing as was the case last year.

CONSOL Energy's coal sales outlook is as follows:



	2Q 2012		2012		2013		2014
Estimated Coal Sales (millions of tons)	14.2 - 14.9		58.9 - 60.9		59.4 - 61.4		63.5 - 65.5
Est. Low-Vol Met Sales	0.7 - 0.9		4.1 - 4.2		4.5 - 4.7		4.3 - 4.5
Tonnage: Firm	0.4		2.2		0.2		—
Avg. Price: Sold (Firm)	$	185.02	$	174.13	$	107.01	$	—
Price: Estimated (For open tonnage)	N/A		N/A		N/A		N/A
Est. High-Vol Met Sales	1.2 -1.3		4.5 - 4.7		5.0 - 5.1		5.6 - 5.8
Tonnage: Firm	0.8		2.4		0.3		0.3
Avg. Price: Sold (Firm)	$	73.32	$	72.66	$	71.69	$	75.53
Price: Estimated (For open tonnage)	N/A		N/A		N/A		N/A
Est. Thermal Sales	12.1 - 12.7		50.0 - 51.7		49.3 - 51.0		53.0 - 54.6
Tonnage: Firm	12.4		50.0		22.8		15.6
Avg. Price: Sold (Firm)	$	61.63	$	62.32	$	63.16	$	64.63
Price: Estimated (For open tonnage)	N/A		N/A		N/A		N/A

Note: N/A means not available or not forecast. CONSOL has chosen not to forecast prices for open tonnage due to ongoing customer

negotiations. In the thermal sales category, the open tonnage includes 4.7 million collared tons in 2013, with a ceiling of $59.78 per ton

and a floor of $51.63 per ton. For 2014, the open tonnage in the thermal sales category includes 7.0 million tons, with a ceiling of

$60.13 per ton and a floor of $46.76 per ton. Total estimated coal sales for 2012, 2013, and 2014 include 0.3, 0.6, and 0.6 million tons,

respectively, from Amonate. The Amonate tons are not included in the category breakdowns. None of the Amonate tons has yet been

sold.

Consol Energy expects to re-start the longwall at Blacksville, which was idled in March, on May 1. The Company has largely concluded negotiations with the thermal coal customers concerning deferred shipments, enabling it to resume longwall production. Also, as the result of negotiations with low volatile metallurgical overseas customers, Buchanan Mine is expected to restart the longwall, which was idled in March, on May 1.

Domestic natural gas production has significantly increased supply due to increased production of gas from shales coupled with an abnormally warm winter season. Supply volumes are up about 9% versus the same period last year. Although the low price environment has created more opportunity for domestic gas-fired electric generation, overall electric demand is down. Longer-term, the abundant domestic gas supply is expected to encourage manufacturing and chemical growth in the U.S. Moreover, recent EPA rulings have created greater incentives for the use of natural gas in the electric generation market.

Low natural gas prices in the first quarter 2012 have accelerated the transition of production from predominantly dry areas towards liquids-rich and oil producing plays. The number of rigs targeting dry-gas has dropped year over year while rigs targeting oil have risen. The Marcellus region has not declined as much as other regions, mainly due to its proximity to consuming Northeast U.S. markets and relatively favorable economics. Exiting the winter withdrawal season, gas storage was 900 Bcf above the same period last year. This will continue to have a dampening effect on gas prices as the market works through record-high storage levels accumulated during the warm winter and production growth begins to moderate.

CONSOL Energy continues to explore for oil and liquids in the Ohio Utica Shale. CONSOL Energy and its joint venture partner plan to drill 22 (gross) wells in 2012. Similarly, in the Marcellus Shale, CONSOL Energy and its joint venture partner are planning to drill 39 (gross) in the liquids-rich area of the play. Many of the remaining 60 (gross) Marcellus Shale wells are being drilled on 100%-net revenue interest acreage , which enables the joint venture to earn an economic return at current gas prices. CONSOL Energy expects its net gas production to be between 157 - 159 Bcf for the year. Second quarter gas production is expected to be approximately 37-38 Bcf.

The slow pace of the global economic recovery continued to temper demand expectations. In the U.S., lingering high unemployment, higher gasoline prices and regulatory uncertainty influenced energy demand while the continued European debt situation, tensions in the Middle East and slowing Chinese growth fueled concerns about the strength of the global recovery.

Despite the current challenges, longer-term fundamental drivers remain sound. With the large amount of coal-fired generation under construction around the world, particularly in developing nations, CONSOL Energy expects the international thermal market to remain strong. Likewise, a continued increase in blast furnace activity in the U.S. and abroad suggests improving overseas demand for metallurgical and cross-over coals to fuel infrastructure development. Domestically, we believe that natural gas demand is expected to rise to take advantage of the low price environment. The fundamental drivers of CONSOL Energy's business remain solid as the Company continues to meet the world's appetite for low-cost, reliable and abundant sources of energy in industrialized and developing markets.

The following developments impacting CONSOL Energy occurred in the three months ended March 31, 2012:

•

CONSOL Energy announced certain changes to the salaried other post-retirement benefit plan that current retirees and current active employees will receive as of January 1, 2014. The change provides a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B and Part D premiums and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug coverage. Employees who work or worked in corporate or operations support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefit. CONSOL Energy remeasured the salaried other postretirement plan as of March 31, 2012 to recognize these changes. The remeasurement reflects the change in benefit and the change in discount rate from 4.51% at December 31, 2011 to 4.57% at March 31, 2012. The remeasurement resulted in a reduction of approximately $80.6 million of Other Post-Retirement Benefits (OPEB) liability with a corresponding offset to Other Comprehensive Income, net of applicable deferred taxes. The change did not result in any reductions to OPEB expense in the three months ended March 31, 2012. OPEB expense is expected to be $9,425 lower than the $148,419 that was expected to be recognized over the remaining nine months of 2012. The change was made to align CONSOL Energy's corporate and operational support compensation package more closely with our peer group.

•

Pennsylvania enacted Act 13 of 2012, which provides for the comprehensive regulation of Marcellus Shale development in Pennsylvania. Among other things, Act 13 requires an impact fee be paid annually on all nonconventional gas wells drilled in the state. The annual fee is based on annual average sales price and is modified annually for a 15-year period for each well. The impact fee also required the first year fee be paid on all applicable wells drilled before January 1, 2012 with subsequent annual fees to apply each year thereafter. CONSOL Energy's retroactive impact fee related to wells drilled prior to January 1, 2012 was approximately $4 million.


•	West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by the permittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special

Reclamation Fund) funded by a per ton fee on coal mined in the State which is used to supplement the site specific bonds if needed in the event of bond forfeiture. The Special Reclamation Fund is currently underfunded. As the result of a decision by the U.S District Court in West Virginia in a citizens' suit concerning the adequacy of the Special Reclamation Fund, effective July 1, 2012, the rate per ton fee on coal mined in the state of West Virginia will be increased from $0.144 cents per ton to $0.279 per ton. CONSOL Energy expects to produce approximately 18 million tons of coal in West Virginia during the second half of 2012.


•	In April 2012, CONSOL Energy entered into an agreement for the sale of its non-core Elk Creek reserves in southern West Virginia. The transaction will be reflected in April 2012 and will result in cash proceeds of approximately $25 million and a gain on sale of assets of approximately $10 million.

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

•

Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations, (ii) increased scrutiny of existing safety regulations and the development of new safety regulations and (iii) additional environmental restrictions such as air emission regulations.

•

Federal and state environmental regulators are reviewing our operations more closely and are more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million. The new facility must be placed into service no later than May 2013.

•

Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011, although the effective date of the rule has been stayed by a court. CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Another example is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011. The new regulations set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOx. Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed. In April 2012, the EPA published its proposed new source emission standards for carbon dioxide for electric power plants. The rule would apply to new power plants and to existing plants that make major modifications. There is a 60 day comment period. If the rule is adopted as proposed, the only new power plants that can meet the proposed emission limits would be coal fired plants with carbon dioxide capture and control and gas fired plants. On April 18, 2012, the EPA published new final rules for gas wells and related facilities. These New Source Performance Standards apply to wells that were hydraulically fractured after August, 23, 2011 and require the implementation by January 1, 2015 of technologies that capture the gas that is currently vented or flared during completion (hydrofracturing) of a well. Low pressure wells, including coalbed methane wells, are excluded from these new standards.


•	CONSOL Energy continues to explore potential sales of non-core assets.

Results of Operations

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011

Net Income

CONSOL Energy reported net income of $97 million, or $0.42 per diluted share, for the three months ended March 31, 2012 . Net income was $192 million, or $0.84 per diluted share, for the three months ended March 31, 2011 .

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $163 million of earnings before income tax for the three months ended March 31, 2012 compared to $299 million for the three months ended March 31, 2011 . The coal division sold 15.1 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, for the three months ended March 31, 2012 compared to 16.4 million tons for the three months ended March 31, 2011 .

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



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Average Sales Price per ton sold	$	69.06	$	68.20	$	0.86		1.3	%
Average Costs per ton sold	54.60		45.44		9.16			20.2	%
Margin	$	14.46	$	22.76	$	(8.30	)	(36.5	)%

The average sales price per ton sold was higher in the period-to-period comparison due to strength in our contracted domestic thermal sales pricing offsetting weakened pricing in the export high-volatile metallurgical coal market. Pricing for low volatile metallurgical coal was slightly increased in the period-to-period comparison. The decreased sales tonnage is due to decreased coal demand for both domestic electric generation and export metallurgical coal.

Average costs per ton sold increased in the period-to-period comparison due to increased variable costs and fixed costs being allocated over fewer sales tons. Labor and labor-related charges increased as a result of additional employees and the impact of the $2.00 per hour worked UMWA contract wage increases. Operating supplies and maintenance costs increased due to additional maintenance, timing of equipment overhaul costs and increased roof control costs. Subsidence costs increased due to the timing and nature of properties undermined and an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison. Depreciation, depletion and amortization costs increased due to additional assets placed in service after the 2011 period. The March 2012 idling of longwalls at the Blacksville mine and the Buchanan mine resulted in an increase in unit costs of approximately $1.19 per ton as the fixed costs were allocated over fewer tons. These increases were partially offset by the improvement in Other Postretirement Benefits discussed in the long-term liabilities section below.

The total gas division includes coalbed methane (CBM), shallow oil and gas, Marcellus and other gas. The total gas division contributed $12 million of earnings before income tax for the three months ended March 31, 2012 compared to $24 million for the three months ended March 31, 2011 . Total gas production was 37.7 billion cubic feet for the three months ended March 31, 2012 compared to 35.9 billion cubic feet for the three months ended March 31, 2011 . Total gas production increased primarily due to the on-going drilling program, offset, in part, by a decrease of 2.4 billion net cubic feet of production related to the Antero divestiture and Noble joint venture.

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



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	4.26	$	4.93	$	(0.67	)	(13.6	)%
Average Costs per thousand cubic feet sold	3.36		3.51		(0.15		)	(4.3	)%
Margin	$	0.90	$	1.42	$	(0.52	)	(36.6	)%

Total gas division outside sales revenue was $161 million for the three months ended March 31, 2012 compared to $177 million for the three months ended March 31, 2011 . The decrease was primarily due to the 13.6% reduction in average sales

price, offset, in part, by the 5.0% increase in volumes sold. The decrease in average sales price is the result of lower general market prices for natural gas, offset, in part, by various gas swap transactions maturing in each period. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 18.3 billion cubic feet of produced gas sales volumes for the three months ended March 31, 2012 at an average price of $5.44 per thousand cubic feet. These financial hedges represented 13.1 billion cubic feet of our produced gas sales volumes for the three months ended March 31, 2011 at an average price of $5.53 per thousand cubic feet.

Total gas division costs decreased for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 primarily due to lower depreciation, depletion and amortization and lower direct administrative, selling and other costs. Lower depreciation, depletion and amortization rates were the result of increased volumes sold reducing the unit cost of straight line depreciation which remained consistent in the period-to-period comparison. Lower direct administrative, selling and other costs were also the result of the increase in volumes sold and actual dollars decreased due to reduced direct administrative labor and other costs. These improvements were offset, in part, by a slight increase in lifting costs in the period-to-period comparison due to increased repairs and maintenance costs.

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

In the quarter ended March 31, 2012, management decided that it would no longer consider general and administrative costs on a segment by segment basis as a factor in their decision making process. These decisions include allocation of capital and individual segment profit performance results. Management did conclude that general and administrative costs would continue to be considered in results at the divisional level (total coal and total gas). In order to present financial information in a manner consistent with internal management's evaluations, the prior periods general and administrative costs have been reclassified to reflect information consistent with the current year's presentation. The total divisional results have not changed. Individual segment results within the division have been recast to reflect costs excluding general and administrative. General and administrative costs are excluded from the coal and gas unit costs above. As in the prior periods, general and administrative costs are allocated between divisions (Coal, Gas, Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. The total general and administrative costs were made up of the following items:



	For the Three Months Ended March 31,
	2012		2011		Variance		Percent Change
Employee wages and related expenses	$	16	$	15	$	1	6.7	%
Consulting and professional services	8		8		—		—	%
Miscellaneous	11		9		2		22.2	%
Total Company General and Administrative Expenses	$	35	$	32	$	3	9.4	%

Total Company General and Administrative Expenses changed due to the following:


•	Employee wages and related expenses increased $1 million in the period-to-period comparison due to annual wage increases and increased employee benefit costs.


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


•	Miscellaneous general and administrative expenses increased slightly in the period-to-period comparison due to various transactions, none of which were individually material.

Included in both coal and gas unit costs are total Company long-term liabilities, such as other postretirement benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability. These long-term liabilities costs are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial calculated liabilities was $70 million for the three months ended March 31, 2012 compared to $76 million for the three months ended March 31, 2011. The decrease of $6 million for total CONSOL Energy expense was primarily due to a decrease in the discount rate assumptions used to calculate expense at the measurement date, which is December 31. See Note 3—Components of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs and Note 4—Components of Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements for additional detail of the total Company expense decrease.

TOTAL COAL SEGMENT ANALYSIS for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 :

The coal segment contributed $163 million of earnings before income tax for the three months ended March 31, 2012 compared to $299 million for the three months ended March 31, 2011 . Variances by the individual coal segments are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	March 31, 2012											March 31, 2011
	Thermal Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	812	$	61	$	173	$	4		$	1,050	$	10		$	(17	)	$	(64	)	$	(3	)	$	(74	)
Purchased Coal	—		—		—		5			5		—			—			—			(1		)	(1		)
Total Outside Sales	812		61		173		9			1,055		10			(17		)	(64		)	(4		)	(75		)
Freight Revenue	—		—		—		49			49		—			—			—			12			12
Other Income	—		5		—		27			32		(2		)	2			—			13			13
Total Revenue and Other Income	812		66		173		85			1,136		8			(15		)	(64		)	21			(50		)
Costs and Expenses:
Total operating costs	530		38		72		41			681		75			8			(1		)	(7		)	75
Total provisions	46		3		8		10			67		(6		)	—			—			(1		)	(7		)
Total direct administrative & other costs	27		3		4		42			76		(1		)	1			—			1			1
Depreciation, depletion and amortization	80		6		10		4			100		5			1			1			(2		)	5
Total Costs and Expenses	683		50		94		97			924		73			10			—			(9		)	74
Freight Expense	—		—		—		49			49		—			—			—			12			12
Total Costs	683		50		94		146			973		73			10			—			3			86
Earnings (Loss) Before Income Taxes	$	129	$	16	$	79	$	(61	)	$	163	$	(65	)	$	(25	)	$	(64	)	$	18		$	(136	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $129 million to total Company earnings before income tax for the three months ended March 31, 2012 compared to $194 million for the three months ended March 31, 2011 . The thermal coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Produced Thermal Tons Sold (in millions)	13.1		13.9		(0.8		)	(5.8	)%
Average Sales Price Per Thermal Ton Sold	$	61.83	$	57.65	$	4.18		7.3	%
Average Operating Costs Per Thermal Ton Sold	40.36		32.71		7.65			23.4	%
Average Provision Costs Per Thermal Ton Sold	3.54		3.76		(0.22		)	(5.9	)%
Average Selling, Direct Administrative and Other Costs Per Thermal Ton Sold	2.02		1.98		0.04			2.0	%
Average Depreciation, Depletion and Amortization Costs Per Thermal Ton Sold	6.11		5.38		0.73			13.6	%
Total Average Costs Per Thermal Ton Sold	$	52.03	$	43.83	$	8.20		18.7	%
Margin Per thermal Ton Sold	$	9.80	$	13.82	$	(4.02	)	(29.1	)%

Thermal coal revenue was $812 million for the three months ended March 31, 2012 compared to $802 million for the three months ended March 31, 2011 . The $10 million increase was attributable to the $4.18 per ton higher average sales price, offset, in part, by the 0.8 million ton reduction in thermal tons sold. The higher average thermal coal sales price in the 2012 period was the result of successful re-negotiation of several domestic thermal contracts whose pricing took effect on January 1, 2012. The sales ton decrease was primarily due to lower natural gas prices, warmer winter temperatures and a sluggish economy adversely impacting domestic electric generation demand for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Produced thermal coal inventory was 2.0 million tons at March 31, 2012 compared to 2.5 million tons at March 31, 2011.

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

Operating costs are comprised of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the thermal coal segment were $530 million in the three months ended March 31, 2012 compared to $455 million in the three months ended March 31, 2011.

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


•	Average operating costs per thermal ton sold increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.


•	Average operating costs per thermal ton sold also increased due to the idling of the Blacksville Mine longwall during the first quarter of 2012. The decrease in tonnage negatively impacted the average operating costs per thermal ton sold by approximately $0.58 per ton.


•	Labor and related benefits average costs per ton sold increased. This was due to additional employees and the impact of the wage increases of $2.00 per hour worked related to the new collective bargaining agreement in the period-to-period comparison.


•	Average operating supplies & maintenance cost per ton sold increased due to higher fuel costs, increased pumpable crib installations, increased equipment maintenance costs and the timing of major equipment overhaul costs in the period-to-period comparison.


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


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

Provision costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, long-term disability and accretion on mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these liabilities are actuarially

calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. The average provision costs attributable to the thermal coal segment were $46 million for the three months ended March 31, 2012 compared to $52 million for the three months ended March 31, 2011. The decrease in the thermal coal provision expense was primarily attributable to a decrease in discount rates used to calculate the cost of the long-term liabilities. This improvement is offset, in part, by the reduction in sales volumes which negatively impacted unit costs.

Selling, direct administrative and other costs attributable to the thermal coal segment include selling, direct administrative costs and other allocated services which directly benefit the segment. Selling costs, excluding commission expense, are allocated to various segments based on a percentage of sales revenue attributable to each segment. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative and other allocated services costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, direct administrative and other costs related to the thermal coal segment were $27 million for the three months ended March 31, 2012 compared to $28 million for the three months ended March 31, 2011. The decrease in total costs was a result of various items, none of which were individually material. The increased average unit costs were related the reduction in sales volumes. Costs were allocated over fewer tons, resulting in higher unit costs.

Depreciation, depletion and amortization for the thermal coal segment was $80 million for the three months ended March 31, 2012 compared to $75 million for the three months ended March 31, 2011. The increase was primarily due to additional equipment and infrastructure placed into service after the 2011 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for thermal coal mines due to additional air shafts being placed into service after the 2011 period which had higher unit rates than historical shafts put into service. These higher expenses coupled with fewer tons sold resulted in a $0.73 increase in average depreciation, depletion and amortization costs per ton sold.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $16 million to total Company earnings before income tax for the three months ended March 31, 2012 compared to $41 million for the three months ended March 31, 2011. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Produced High Vol Met Tons Sold (in millions)	1.0		1.0		—			—	%
Average Sales Price Per High Vol Met Ton Sold	$	62.18	$	75.25	$	(13.07	)	(17.4	%)
Average Operating Costs Per High Vol Met Ton Sold	39.44		28.47		10.97			38.5	%
Average Provision Costs Per High Vol Met Ton Sold	3.04		2.95		0.09			3.1	%
Average Selling, Direct Administrative and Other Costs Per High Vol Met Ton Sold	2.48		2.03		0.45			22.2	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	6.01		5.15		0.86			16.7	%
Total Average Costs Per High Vol Met Ton Sold	$	50.97	$	38.60	$	12.37		32.0	%
Margin Per High Vol Met Ton Sold	$	11.21	$	36.65	$	(25.44	)	(69.4	%)

High volatile metallurgical coal revenue was $61 million for the three months ended March 31, 2012 compared to $78 million for the three months ended March 31, 2011. Average sales prices for high volatile metallurgical coal decreased compared to prior quarter due to weakening in global metallurgical coal demand. CONSOL Energy priced 0.8 million tons of high volatile metallurgical coal in the export market at an average sales price of $59.22 per ton for the three months ended March 31, 2012 compared to 1.0 million tons at an average price of $75.25 per ton for the three months ended March 31, 2011.

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

Operating costs related to the high volatile metallurgical coal segment were $38 million for the three months ended March 31, 2012 compared to $30 million for the three months ended March 31, 2011. Changes in average operating costs per ton for high volatile metallurgical coal sold were primarily related to the following items:

•

Average operating costs per unit increased due to the mix of mines shipping high volatile metallurgical coal. The increased cost structure of high volatile metallurgical coal is due to more Central Appalachian mines shipping high vol tons. Central Appalachian mines shipping high volatile metallurgical tons have higher cost structures than the Northern Appalachian mines included in the prior period.


•	Labor and related benefits increased due to higher employee counts and additional hours worked in the period-to- period comparison.

•

Average operating supplies & maintenance costs per ton sold increased due to additional maintenance, equipment overhaul costs and increased fuel and blasting costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced and major equipment overhauls in the current period. Additional fuel and blasting costs were due to increased surface tonnage moved in the period-to-period comparison.


•	In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the Central Appalachian mines which shipped high volatile metallurgical coal in the current period.


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

The provision expense attributable to the high volatile metallurgical coal segment was $3 million for the three months ended March 31, 2012 and 2011. The per unit increase was due to fewer tons sold in the period-to-period comparison.

Selling, direct administrative and other costs attributable to the high volatile coal segment include selling, direct administrative costs and other allocated services which directly benefit the segment. Selling costs, excluding commission expense, are allocated to various segments based on a percentage of sales revenue attributable to each segment. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative and other allocated services costs are costs associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, direct administrative and other costs related to the high volatile metallurgical coal segment were $3 million for the three months ended March 31, 2012 compared to $2 million for the three months ended March 31, 2011. The per unit increase was due to fewer tons sold in the period-to-period comparison.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $6 million for the three months ended March 31, 2012 compared to $5 million for the three months ended March 31, 2011. The increase was primarily due to additional equipment and infrastructure placed into service after the 2011 period that is depreciated on a straight-line basis.

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

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $79 million to total Company earnings before income tax for the three months ended March 31, 2012 compared to $143 million for the three months ended March 31, 2011. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)	1.0		1.4		(0.4		)	(28.6	)%
Average Sales Price Per Low Vol Met Ton Sold	$	167.87	$	165.71	$	2.16		1.3	%
Average Operating Costs Per Low Vol Met Ton Sold	$	69.68	$	51.21	$	18.47		36.1	%
Average Provision Costs Per Low Vol Met Ton Sold	$	7.62	$	5.94	$	1.68		28.3	%
Average Selling, Direct Administrative and Other Costs Per Low Vol Met Ton Sold	$	3.88	$	2.78	$	1.10		39.6	%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	9.57	$	6.03	$	3.54		58.7	%
Total Average Costs Per Low Vol Met Ton Sold	$	90.75	$	65.96	$	24.79		37.6	%
Margin Per Low Vol Met Ton Sold	$	77.12	$	99.75	$	(22.63	)	(22.7	)%

Low volatile metallurgical coal revenue was $173 million for the three months ended March 31, 2012 compared to $237 million for the three months ended March 31, 2011. The $64 million decrease was attributable to the 0.4 million ton decrease in sales tons, offset, in part, by a $2.16 per ton increase in average sales price. CONSOL Energy priced 0.8 million tons of low volatile metallurgical coal in the export market at an average sales price of $163.74 per ton for the three months ended March 31, 2012 compared to 1.2 million tons at an average price of $167.52 per ton for the three months ended March 31, 2011. Produced low volatile metallurgical coal inventory was 0.2 million tons at March 31, 2012 and 2011.

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the low volatile metallurgical coal segment were $72 million for the three months ended March 31, 2012 compared to $73 million for the three months ended March 31, 2011. Changes in average operating costs per ton sold of low volatile metallurgical coal were primarily related to the following items:


•	Average operating costs per low volatile ton sold primarily increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.


•	Average operating costs per low volatile ton sold also increased due to the idling of the Buchanan Mine longwall in March 2012. The decrease in tonnage negatively impacted the average operating costs per low volatile ton sold by approximately $16.46 per ton.


•	Average labor and related benefits increased in the period-to-period comparison due to additional employees and increased wages.


•	Average operating supplies and maintenance costs were impaired due to the decreased sales tonnage; however, total operating supplies and maintenance costs were improved due to the idling of longwall operations during the current period.


•	Average gas well plugging and degasification costs were improved do to fewer degasification wells drilled in the current period.

The provision expense attributable to the low volatile metallurgical coal segment was $8 million for the three months ended March 31, 2012 and 2011. The per unit increase was due to fewer tons sold in the period-to-period comparison.

Selling, direct administrative and other costs attributable to the low volatile coal segment include selling, direct administrative costs and other allocated services which directly benefit the segment. Selling costs, excluding commission expense, are allocated to various segments based on a percentage of sales revenue attributable to each segment. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct administrative and other allocated services costs are costs associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Selling, direct administrative and other costs related to the low volatile metallurgical coal segment were $4 million for the three months ended March 31, 2012 and 2011. The per unit increase was due to fewer tons sold in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $10 million for the three months ended March 31, 2012 compared to $9 million for the three months ended March 31, 2011. The increase was primarily due to additional equipment and infrastructure placed into service after the 2011 period that is depreciated on a straight-line basis. These increases were offset, in part, by lower total costs for units-of-production amortization due to the decreased tonnage. The decrease in sales tons increased average unit cost for depreciation, depletion and amortization due to fixed straight-line basis costs being allocated over fewer tons.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $61 million for the three months ended March 31, 2012 compared to a loss before income tax of $79 million for the three months ended March 31, 2011. The other coal segment includes purchased coal activities, idle mine activities, coal general and administrative costs as well as various activities assigned to the coal division but not allocated to each individual mine.

Other coal segment produced coal sales include revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the three months ended March 31, 2012 compared to 0.2 million tons for the three months ended March 31, 2011. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The revenues were $5 million for the three months ended March 31, 2012 compared to $6 million for the three months ended March 31, 2011. The decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset in freight expense. Freight revenue was $49 million for the three months ended March 31, 2012 compared to $37 million for the three months ended March 31, 2011. The $12 million increase in freight expense is due to increased shipments on contracts for which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $27 million for the three months ended March 31, 2012 compared to $14 million for the three months ended March 31, 2011. The increase of $13 million primarily related to various miscellaneous sales of property and sales of coal and surface lands that resulted in $19 million of gain. This improvement was partially offset by various transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total costs were $146 million for the three months ended March 31, 2012 compared to $143 million for the three months ended March 31, 2011. The increase of $3 million was due to the following items:



	For the Three Months Ended March 31,
	2012		2011		Variance
Freight Expense	$	49	$	37	$	12
Purchased Coal	12		13		(1		)
Closed and idle mines	21		26		(5		)
Other	64		67		(3		)
Total other coal segment costs	$	146	$	143	$	3

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset in freight revenue. Freight expense increased $12 million primarily due to increased shipments on contracts for which CONSOL Energy contractually provides transportation services.


•	Purchased coal costs decreased approximately $1 million in the period-to-period comparison primarily due to various transactions that occurred throughout both periods, none of which were individually material.

•

Closed and idle mine costs decreased approximately $5 million for the three months ended March 31, 2012 compared to the three months ended March 31, 2011. Closed and idle mine costs decreased $3 million as the result of a decision to permanently abandon Mine 84. Closed and idle mine costs decreased $2 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.


•	Other expenses related to the coal segment decreased $3 million in the period-to-period comparison due to various miscellaneous transactions, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 :

The gas segment contributed $12 million to the total Company earnings before income tax for the three months ended March 31, 2012 compared to $24 million for the three months ended March 31, 2011 .



	For the Three Months Ended												Difference to Three Months Ended
	March 31, 2012												March 31, 2011
	CBM		Shallow Oil & Gas			Marcellus		Other Gas			Total Gas		CBM			Shallow Oil & Gas			Marcellus			Other Gas			Total Gas
Sales:
Produced	$	99	$	34		$	24	$	3		$	160	$	(15	)	$	(4	)	$	3		$	—		$	(16	)
Related Party	1		—			—		—			1		—			—			—			—			—
Total Outside Sales	100		34			24		3			161		(15		)	(4		)	3			—			(16		)
Gas Royalty Interest	—		—			—		12			12		—			—			—			(7		)	(7		)
Purchased Gas	—		—			—		1			1		—			—			—			—			—
Other Income	—		—			—		16			16		—			—			—			15			15
Total Revenue and Other Income	100		34			24		32			190		(15		)	(4		)	3			8			(8		)
Lifting	9		10			4		—			23		(1		)	1			2			—			2
Ad Valorem, Severance, and Other Taxes	3		3			1		—			7		—			—			1			—			1
Gathering	25		6			4		—			35		2			(1		)	1			—			2
Gas Direct Administrative, Selling & Other	5		4			3		1			13		—			(1		)	1			(3		)	(3		)
Depreciation, Depletion and Amortization	22		15			9		4			50		(2		)	(2		)	3			1			—
General & Administration	—		—			—		10			10		—			—			—			1			1
Gas Royalty Interest	—		—			—		10			10		—			—			—			(7		)	(7		)
Purchased Gas	—		—			—		1			1		—			—			—			—			—
Exploration and Other Costs	—		—			—		5			5		—			—			—			2			2
Other Corporate Expenses	—		—			—		23			23		—			—			—			8			8
Interest Expense	—		—			—		1			1		—			—			—			(2		)	(2		)
Total Cost	64		38			21		55			178		(1		)	(3		)	8			—			4
Earnings Before Income Tax	$	36	$	(4	)	$	3	$	(23	)	$	12	$	(14	)	$	(1	)	$	(5	)	$	8		$	(12	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $36 million to the total Company earnings before income tax for the three months ended March 31, 2012 compared to $50 million for the three months ended March 31, 2011 .



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)	22.7		22.4		0.3			1.3	%
Average CBM sales price per thousand cubic feet sold	$	4.40	$	5.12	$	(0.72	)	(14.1	)%
Average CBM lifting costs per thousand cubic feet sold	$	0.41	$	0.43	$	(0.02	)	(4.7	)%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	$	0.12	$	0.14	$	(0.02	)	(14.3	)%
Average CBM gathering costs per thousand cubic feet sold	$	1.08	$	1.01	$	0.07		6.9	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	$	0.23	$	0.22	$	0.01		4.5	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	0.96	$	1.09	$	(0.13	)	(11.9	)%
Total Average CBM costs per thousand cubic feet sold	$	2.80	$	2.89	$	(0.09	)	(3.1	)%
Average Margin for CBM	$	1.60	$	2.23	$	(0.63	)	(28.3	)%

CBM sales revenues were $100 million for the three months ended March 31, 2012 compared to $115 million for the three months ended March 31, 2011 . The $15 million decrease was primarily due to a 14.1% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 1.3% increase in average volumes sold. The decrease in CBM average sales price is the result of lower general market prices for natural gas, offset, in part, by various gas swap transactions maturing in each period. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 11.4 billion cubic feet of our produced CBM gas sales volumes for the three months ended March 31, 2012 at an average price of $5.63 per thousand cubic feet. In the three months ended March 31, 2011, these financial hedges represented 11.8 billion cubic feet at an average price of $5.62 per thousand cubic feet. CBM sales volumes increased 0.3 billion cubic feet primarily due to additional wells coming on-line from our on-going drilling program, offset, in part, by a decrease in volumes related to the Buchanan longwall being idled.

Total costs for the CBM segment were $64 million for the three months ended March 31, 2012 compared to $65 million for the three months ended March 31, 2011 . Lower costs in the period-to-period comparison were primarily related to lower unit costs offset, in part, by increased volumes sold.

CBM lifting costs were $9 million in the three months ended March 31, 2012 compared to $10 million in the three months ended March 31, 2011 . Lower average CBM lifting unit costs were related to a prior year contract buyout that eliminated idle rig fees that were incurred in the 2011 period, offset, in part, by increased well site maintenance due to slip repairs.

CBM ad valorem, severance and other taxes were $3 million in the three months ended March 31, 2012 and 2011. The improvement in unit costs was primarily due to increased volumes.

CBM gathering costs were $25 million for the three months ended March 31, 2012 compared to $23 million for the three months ended March 31, 2011 . The $2 million increase was due to increased direct labor associated with gathering activities.

CBM direct administrative, selling & other costs for the CBM segment were $5 million for both the three months ended March 31, 2012 and 2011. Direct administrative selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts.

Depreciation, depletion and amortization attributable to the CBM segment was $22 million for the three months ended March 31, 2012 compared to $24 million for the three months ended March 31, 2011. There was approximately $15 million, or $0.68 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a unit-of-production method of depreciation for the three months ended March 31, 2012. The production portion of depreciation, depletion and amortization was $17 million, or $0.79 per unit-of-production for the three months ended March 31, 2011. The unit-of-production rates are generally calculated using the net book value of assets divided by either proved or proved developed reserves. 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 March 31, 2012. There was $7 million, or $0.30 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended March 31, 2011. The $1 million decrease was due to various items, none of which were individually material.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $4 million in the three months ended March 31, 2012 compared to a loss before income tax of $3 million in the three months ended March 31, 2011.



	For the Three Months Ended March 31,
	2012			2011			Variance			Percent Change
Produced gas Shallow oil and Gas sales volumes (in billion cubic feet)	7.6			8.2			(0.6		)	(7.3	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	4.53		$	4.75		$	(0.22	)	(4.6	)%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	$	1.32		$	1.16		$	0.16		13.8	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	$	0.35		$	0.36		$	(0.01	)	(2.8	)%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	$	0.78		$	0.85		$	(0.07	)	(8.2	)%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	$	0.59		$	0.63		$	(0.04	)	(6.3	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.98		$	2.08		$	(0.10	)	(4.8	)%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	$	5.02		$	5.08		$	(0.06	)	(1.2	)%
Average Margin for Shallow Oil and Gas	$	(0.49	)	$	(0.33	)	$	(0.16	)	48.5	%

Shallow Oil and Gas sales revenues were $34 million for the three months ended March 31, 2012 compared to $38 million for the three months ended March 31, 2011. The $4 million decrease was primarily due to the 7.3% decrease in volumes sold. Shallow Oil and Gas sales volumes decreased 0.6 billion cubic feet for the three months ended March 31, 2012 compared to the 2011 period primarily due to normal well declines without a corresponding increase in wells drilled. The focus of the gas division is to develop the Marcellus and Utica acreage. Average sales price decreased primarily due to lower general market prices of natural gas in the period-to-period comparison. This decrease was partially offset by the result of various gas swap transactions that matured in the three months ended March 31, 2012. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 4.1 billion cubic feet of our produced Shallow Oil and Gas gas sales volumes for the three months ended March 31, 2012 at an average price of $5.22 per thousand cubic feet. There were no Shallow Oil and Gas gas swap transactions that occurred in the three months ended March 31, 2011.

Total costs for the Shallow Oil and Gas segment were $38 million for the three months ended March 31, 2012 compared to $41 million for the three months ended March 31, 2011.

Shallow Oil and Gas lifting costs were $10 million for the three months ended March 31, 2012 compared to $9 million for the three months ended March 31, 2011. Lifting costs per unit increased due to increased equipment maintenance costs, increased water line costs, increased non-operated well costs and increased direct labor costs. Average lifting costs per unit were also negatively impacted by the decrease in sales volumes.

Shallow Oil and Gas ad valorem, severance and other taxes were $3 million for the three months ended March 31, 2012 and 2011. Costs were consistent in the period-to-period comparison.

Shallow Oil and Gas gathering costs were $6 million for the three months ended March 31, 2012 compared to $7 million for the three months ended March 31, 2011. Gathering costs decreased primarily due to lower transportation costs and pipeline maintenance.

Shallow Oil and Gas direct administrative, selling & other costs related to the Shallow Oil and Gas gas segment were $4 million for the three months ended March 31, 2012 compared to $5 million for the three months ended March 31, 2011. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The $1 million decrease in the period-to-period comparison is due to Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes.

Depreciation, depletion and amortization costs were $15 million for the three months ended March 31, 2012 compared to $17 million for the three months ended March 31, 2011. There was approximately $13 million, or $1.73 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2012. There was approximately $15 million, or $1.85 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2011. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $2 million, or $0.25 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended March 31, 2012. There was $2 million, or $0.23 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended March 31, 2011.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $3 million to the total Company earnings before income tax for the three months ended March 31, 2012 compared to $8 million for the three months ended March 31, 2011.



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)	6.7		4.8		1.9			39.6	%
Average Marcellus sales price per thousand cubic feet sold	$	3.54	$	4.35	$	(0.81	)	(18.6	)%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.59	$	0.36	$	0.23		63.9	%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	$	0.13	$	0.06	$	0.07		116.7	%
Average Marcellus gathering costs per thousand cubic feet sold	$	0.59	$	0.58	$	0.01		1.7	%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	$	0.41	$	0.35	$	0.06		17.1	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.34	$	1.25	$	0.09		7.2	%
Total Average Marcellus costs per thousand cubic feet sold	$	3.06	$	2.60	$	0.46		17.7	%
Average Margin for Marcellus	$	0.48	$	1.75	$	(1.27	)	(72.6	)%

The Marcellus segment sales revenues were $24 million for the three months ended March 31, 2012 compared to $21 million for the three months ended March 31, 2011. The decrease in Marcellus average sales price was the result of lower general market prices, offset, in part, by various gas swap transactions that matured in the three months ended March 31, 2012. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 2.8 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended March 31, 2012 at an average price of $4.98 per thousand cubic feet. These financial hedges represented 1.3 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended March 31, 2011 at an average price of $4.71 per thousand cubic feet. The increased sales volumes are primarily due to additional wells coming on-line from our on-going drilling program, offset, in part, by a decrease of 2.4 billion net cubic feet of production related to the Antero

divestiture and Noble joint venture. At March 31, 2012, there were 114 Marcellus Shale wells in production. At March 31, 2011, there were 60 Marcellus Shale wells in production.

Marcellus lifting costs were $4 million for the three months ended March 31, 2012 compared to $2 million for the three months ended March 31, 2011. Lifting costs per unit increased $0.23 per thousand cubic feet sold due to increased repairs and maintenance, increased environmental compliance and safety compliance, increased direct labor and increased well site maintenance. These increases were partially offset by the increased sales volumes.

Marcellus ad valorem, severance and other taxes were $1 million in the period ended March 31, 2012 compared to less than $1 million in the period ended March 31, 2011. The increase in the current period per unit cost is primarily due to new legislation passed in the state of Pennsylvania (Act 13 of 2012, House Bill 1950). This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within Pennsylvania.

Marcellus gathering costs were $4 million for the three months ended March 31, 2012 compared to $3 million for the three months ended March 31, 2011. Marcellus gathering average unit costs were consistent in the period-to-period comparison.

Marcellus direct administrative, selling & other costs related to the Marcellus gas segment were $3 million for the three months ended March 31, 2012 compared to $2 million for the three months ended March 31, 2011. Direct administrative, selling & other costs attributable to the total gas division are allocated to the individual gas segments based on a combination of production and employee counts. The $1 million increase in the period-to-period comparison is due to Marcellus volumes representing a larger proportion of total natural gas volumes.

Depreciation, depletion and amortization costs were $9 million for the three months ended March 31, 2012 compared to $6 million for the three months ended March 31, 2011. There was approximately $8 million, or $1.20 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2012. There was approximately $5 million, or $0.99 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2011. The rate is calculated by taking the net book value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was $1 million, or $0.14 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis in the three months ended March 31, 2012. There was $1 million, or $0.26 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis in the three months ended March 31, 2011. The $0.12 decrease in unit is due to increased production volumes. Fixed costs are allocated over more volumes, resulting in lower unit costs.

OTHER GAS SEGMENT

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

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $3 million for the three months ended March 31, 2012 and 2011. Total costs related to these other sales were $5 million in the 2012 period and were $3 million in the 2011 period. The increase in costs is due to various items, none of which are individually material. A per unit analysis of the other operating costs in the Chattanooga shale is not meaningful due to the low volumes produced in the period-to-period analysis.

General and administrative costs are allocated to the total gas segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $10 million for the three month ended March 31, 2012 compared to $11 million for the three months ended March 31, 2011. Refer to the discussion of total general and administrative costs contained in the section "Net Income " of this quarterly report.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas sales revenue was $12 million for the three months ended March 31, 2012 compared to $19 million for the three months ended March 31, 2011. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.1		4.3		(0.2		)	(4.7	)%
Average Sales Price Per thousand cubic feet	$	2.96	$	4.38	$	(1.42	)	(32.4	)%

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 $1 million for each of the three months ended March 31, 2012 and 2011.



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.3		0.2		0.1			50.0	%
Average Sales Price Per thousand cubic feet	$	3.01	$	4.50	$	(1.49	)	(33.1	)%

Other income was $16 million for the three months ended March 31, 2012 compared to $1 million for the three months ended March 31, 2011. The $15 million increase was due to $8 million of interest income in the current period due to notes receivable from Noble related to the September 2011 joint venture agreement, a $6 million increase in gain on sale of miscellaneous assets and a $1 million increase in equity in earnings of affiliates.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas costs were $10 million for the three months ended March 31, 2012 compared to $17 million for the three months ended March 31, 2011. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.1		4.3		(0.2		)	(4.7	)%
Average Cost Per thousand cubic feet sold	$	2.49	$	3.91	$	(1.42	)	(36.3	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million for both the three months ended March 31, 2012 and 2011.



	For the Three Months Ended March 31,
	2012		2011		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.3		0.2		0.1			50.0	%
Average Cost Per thousand cubic feet sold	$	1.62	$	2.27	$	(0.65	)	(28.6	)%

Exploration and other costs were $5 million for the three months ended March 31, 2012 compared to $3 million for the three months ended March 31, 2011. Costs included in the exploration and other cost line are detailed as follows:



	For the Three Months Ended March 31,
	2012		2011		Variance		Percent Change
Exploration	$	2	$	2	$	—	—	%
Dry Hole and Lease Expiration Costs	1		1		$	—	100.0	%
Other	2		—		$	2	100.0	%
Total Exploration and Other Costs	$	5	$	3	$	2	66.7	%


•	Other costs were $2 million higher in the period-to-period comparison primarily due to environmental clean-up costs incurred during the three months ended March 31, 2012 at several well sites.

Other corporate expenses were $23 million for the three months ended March 31, 2012 compared to $15 million for the three months ended March 31, 2011. The $8 million increase in the period-to-period comparison was made up of the following items:



	For the Three Months Ended March 31,
	2012		2011		Variance		Percent Change
Short-term incentive compensation	$	7	$	5	$	2	40.0	%
Stock-based compensation	6		5		1		20.0	%
PA impact fees	4		—		4		100.0	%
Unutilized firm transportation	2		2		—		—	%
Bank fees	2		2		—		—	%
Other	2		1		1		100.0	%
Total Other Corporate Expenses	$	23	$	15	$	8	53.3	%


•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period.


•	Stock-based compensation was higher in the period-to-period comparison due to an increased allocation from CONSOL Energy as a result of an increase in total CONSOL Energy stock-based compensation expense. The increase in CONSOL Energy stock-based compensation expense is due to additional awards granted in the period-to-period comparison.

•

PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. On-going PA impact fees which relate to current year wells drilled are included as part of lifting costs in the Marcellus gas segment.


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


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


•	Other expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Interest expense related to the other gas segment was $1 million for the three months ended March 31, 2012 compared to $3 million for the three months ended March 31, 2011. The $2 million decrease in interest expense in the period-to-period comparison is primarily due to lower average borrowings during the period on the CNX Gas Credit Facility.

OTHER SEGMENT ANALYSIS for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 :

The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segments. The other segment had a loss before income tax of $56 million for the three months ended March 31, 2012 compared to a loss before income tax of $72 million for the three months ended March 31, 2011 . The other segment also included total company income tax expense of $21 million for the three months ended March 31, 2012 compared to $59 million for the three months ended March 31, 2011 .



	For the Three Months Ended March 31,
	2012			2011			Variance			Percent Change
Sales—Outside	$	97		$	79		$	18		22.8	%
Other Income	4			3			1			33.3	%
Total Revenue	101			82			19			23.2	%
Cost of Goods Sold and Other Charges	90			83			7			8.4	%
Depreciation, Depletion & Amortization	6			4			2			50.0	%
Taxes Other Than Income Tax	4			3			1			33.3	%
Interest Expense	57			64			(7		)	(10.9	)%
Total Costs	157			154			3			1.9	%
Loss Before Income Tax	(56		)	(72		)	16			22.2	%
Income Tax	21			59			(38		)	(64.4	)%
Net Loss	$	(77	)	$	(131	)	$	54		41.2	%

Industrial supplies:

Total revenue from industrial supplies was $69 million for the three months ended March 31, 2012 compared to $54 million for the three months ended March 31, 2011 . The increase was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $68 million for the three months ended March 31, 2012 compared to $58 million for the three months ended March 31, 2011 . The increase of $10 million was primarily related to higher sales volumes.

Transportation operations:

Total revenue from transportation operations was $30 million for the three months ended March 31, 2012 compared to $27 million for the three months ended March 31, 2011 . The increase of $3 million was primarily attributable to 1.1 million more tons transported in the period-to-period comparison.

Total costs related to the transportation operations were $21 million for the three months ended March 31, 2012 and for the three months ended March 31, 2011 .

Miscellaneous other:

Additional other income of $2 million was recognized for the three months ended March 31, 2012 compared to $1 million for the three months ended March 31, 2011 . The $1 million increase was due to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest expense, bank fees and various other miscellaneous corporate charges. Total other costs were $68 million for the three months ended March 31, 2012 compared to $75 million for the three months ended March 31, 2011 . Other corporate costs decreased due to the following items:



	For the Three Months Ended March 31,
	2012		2011		Variance
Interest expense	$	57	$	64	$	(7	)
Bank fees	4		6		(2		)
Evaluation fees for non-core asset dispositions	1		1		—
Other	6		4		2
	$	68	$	75	$	(7	)

•

Interest expense primarily decreased $4 million due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period. Interest expense also decreased $2 million in the period-to-period comparison primarily due to the 2011 redemption of the 7.875% notes that were due in 2012, being replaced by the 2011 issuance of the 6.375% senior unsecured notes due March 2021. Additionally, a $1 million decrease in interest expense is due to lower borrowings on the revolving credit facilities.


•	Bank fees decreased $2 million due to lower borrowings on the CNX Gas revolving credit facility in the period-to-period comparison.


•	Evaluation fees for non-core asset dispositions remained consistent in the period-to-period comparison.


•	Other corporate items increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 18.0% in the three months ended March 31, 2012 compared to 23.5% in the three months ended March 31, 2011 . The relationship between pre-tax earnings and percentage depletion also impacts the effective tax rate. See Note 5—Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Three Months Ended March 31,
	2012			2011			Variance			Percent Change
Total Company Earnings Before Income Tax	$	119		$	251		$	(132	)	(52.6	)%
Income Tax Expense	$	21		$	59		$	(38	)	(64.4	)%
Effective Income Tax Rate	18.0		%	23.5		%	(5.5		)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CONSOL Energy's $1.5 billion Senior Secured Credit Agreement expires April 12, 2016. CONSOL Energy's credit facility allows for up to $1.5 billion for borrowings and letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 5.84 to 1.00 at March 31, 2012 . The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00 thereafter, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CONSOL Energy and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, for CONSOL Energy and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 2.10 to 1.00 at March 31, 2012 . The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio covenant is calculated as the ratio of secured debt to EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on the revolving credit facility. The senior secured leverage ratio was 0.07 to 1.00 at March 31, 2012 . Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another company and amend, modify or restate, in any material way, the senior unsecured notes. At March 31, 2012 , the facility had no outstanding borrowings and $ 101 million of letters of credit outstanding, leaving $ 1.4 billion of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $200 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper rates plus a charge for administrative services paid to financial institutions. At March 31, 2012 , eligible accounts receivable totaled approximately $200 million. At March 31, 2012 , the facility had no outstanding borrowings and $ 161 million of letters of credit outstanding, leaving $ 39 million of unused capacity.

CNX Gas's $1.0 billion Senior Secured Credit Agreement expires April 12, 2016. CNX Gas' credit facility allows for up to $1.0 billion for borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 35.79 to 1.00 at March 31, 2012 . The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CNX Gas and its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, for CNX Gas and its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.00 to 1.00 at March 31, 2012 . Covenants in the facility limit CNX Gas' ability to dispose of assets, make investments, pay dividends and merge with another company. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in the CONE Gathering Company are unrestricted. At March 31, 2012 , the facility had no amounts drawn and $ 70 million of letters of credit outstanding, leaving $ 930 million of unused capacity.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact our collection of trade receivables. As a result, CONSOL Energy constantly

monitors the creditworthiness of our customers. We believe that our current group of customers are financially sound and represent no abnormal business risk.

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $ 296 million at March 31, 2012 . The ineffective portion of these contracts was insignificant to earnings in the three months ended March 31, 2012 . No issues related to our hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Three Months Ended March 31,
	2012			2011			Change
Cash flows from operating activities	$	229		$	435		$	(206	)
Cash used in investing activities	$	(288	)	$	(253	)	$	(35	)
Cash used in financing activities	$	(30	)	$	(87	)	$	57

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


•	Operating cash flow decreased $95 million in 2012 due to lower net income in the period-to-period comparison.


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

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


•	During the 2012 period, $14 million was contributed to CONE Gathering LLC (CONE) in order to meet the operating and capital expenditure needs of the joint venture. The joint venture, of which CONSOL Energy owns 50%, was established on September 30, 2011 to develop and operate the gas gathering system in the Marcellus Shale play.

•

Total capital expenditures increased $52 million to $306 million in the three months ended March 31, 2012 compared to $254 million in the three months ended March 31, 2011. Capital expenditures for the gas segment decreased $55 million primarily due to a decrease in Marcellus Shale drilling in the period-to-period comparison. Capital expenditures for coal and other activities increased $107 million in the period-to-period comparison. The ongoing development and expenditures of the BMX mine, which is scheduled to go on-line in 2014, increased $30 million in the period-to-period comparison. Capital expenditures for the Northern West Virginia RO system were $18 million for the 2012 period. The remaining increase was due to various projects throughout both periods, none of which were individually material.


•	Proceeds from the sale of assets increased $28 million in the period-to-period comparison primarily due to the sale of several non-core assets including previously mined surface properties and rights-of-way.

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


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


•	In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility.


•	In 2011, CONSOL Energy paid outstanding borrowings of $113 million under the revolving credit facilities. CONSOL Energy had no amounts outstanding on the revolving credit facilities for the three months ended March 31, 2012.


•	Dividends of $28 million were paid in 2012 compared to $23 million in 2011. This is due to the increase of the quarterly dividend by 25%, or $0.10 per share, to $0.125 per share in the 2012 period.

The following is a summary of our significant contractual obligations at March 31, 2012 (in thousands):



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase Order Firm Commitments	$	465,999	$	62,067			$	—	$	528,066
Gas Firm Transportation	66,385		160,914		143,171		493,535		864,005
CONE Gathering Commitments	30,750		180,925		355,100		1,146,000		1,712,775
Long-Term Debt	11,759		6,279		5,287		3,110,668		3,133,993
Interest on Long-Term Debt	244,977		490,592		491,303		543,230		1,770,102
Capital (Finance) Lease Obligations	9,120		14,997		10,846		28,641		63,604
Interest on Capital (Finance) Lease Obligations	4,174		6,699		5,046		5,171		21,090
Operating Lease Obligations	91,951		157,647		99,546		152,095		501,239
Long-Term Liabilities—Employee Related (a)	224,974		464,339		479,746		2,384,033		3,553,092
Other Long-Term Liabilities (b)	369,123		121,316		65,938		445,723		1,002,100
Total Contractual Obligations (c)	$	1,519,212	$	1,665,775	$	1,655,983	$	8,309,096	$	13,150,066

_________________________


(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2012 contributions are expected to approximate $ 110 million.


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


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

Debt

At March 31, 2012 , CONSOL Energy had total long-term debt of $3.198 billion outstanding, including the current portion of long-term debt of $21 million. This long-term debt consisted of:


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


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


•	An aggregate principal amount of $ 250 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.


•	An aggregate principal amount of $ 103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.


•	$ 31 million in advance royalty commitments with an average interest rate of 6.73% per annum.


•	An aggregate principal amount of $ 64 million of capital leases with a weighted average interest rate of 6.32% per annum.

At March 31, 2012 , CONSOL Energy also had no outstanding borrowings and had approximately $ 101 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At March 31, 2012 , CONSOL Energy had no outstanding borrowings and had $161 million of letters of credit outstanding under the accounts receivable securitization facility.

At March 31, 2012 , CNX Gas, a wholly owned subsidiary, had no outstanding borrowings and approximately $ 70 million of letters of credit outstanding under its $1.0 billion secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $3.8 billion at March 31, 2012 and $3.6 billion at December 31, 2011 . Total equity increased primarily due to net income, changes in the fair value of cash flow hedges, adjustments to actuarial liabilities, and the amortization of stock-based compensation awards. These increases were offset, in part, by the declaration of dividends and the issuance of treasury stock. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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



Declaration Date	Amount Per Share		Record Date	Payment Date
April 27, 2012	$	0.125	May 11, 2012	May 25, 2012
January 27, 2012	$	0.125	February 7, 2012	February 21, 2012

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 $0.50 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 2.10 to 1.00 and our availability was approximately $1.4 billion at March 31, 2012 . The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.50 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the three months ended March 31, 2012 .

Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at March 31, 2012 . The various multi-employer benefit plans are discussed in Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2011 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 March 31, 2012 . Management believes these items will expire without being funded. See Note 11—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Forward-Looking Statements

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


•	deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;


•	a significant or extended decline in prices we receive for our coal and natural gas affecting our operating results and cash flows;


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


•	our reliance on major customers;


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


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


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


•	our inability to maintain satisfactory labor relations;


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


•	the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for coal and natural gas


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


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


•	decreases in the availability of, or increases in, the price of commodities or capital equipment used in our mining operations;


•	decreases in the availability of, an increase in the prices charged by third party contractors or, failure of third party contractors to provide quality services to us in a timely manner could impact our profitability;


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


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


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


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


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


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


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


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


•	the impacts of various asbestos litigation claims;


•	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;


•	our accruals for obligations for long-term employee benefits are based upon assumptions which, if inaccurate, could result in our being required to expend greater amounts than anticipated;


•	due to our participation in an underfunded multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees and in the future we may have to make additional cash contributions to fund the pension plan or incur withdrawal liability;


•	lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in a plan year;

•

acquisitions and joint ventures that we recently have completed or entered into or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made and divestitures we anticipate may not occur or produce anticipated proceeds including joint venture partners paying anticipated carry obligations;


•	the terms of our existing joint ventures restrict our flexibility and actions taken by the other party in our gas joint ventures may impact our financial position;


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


•	risks associated with our debt;


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


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


•	other factors discussed in our 2011 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

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

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CONSOL Energy's 2011 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at March 31, 2012 . A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $16.2 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $16.2 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At March 31, 2012 , CONSOL Energy had $3,198 million aggregate principal amount of debt outstanding under fixed-rate instruments and no debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings during the three months ended March 31, 2012 . CNX Gas did not have borrowings under its revolving credit facility for the three months ended March 31, 2012 . A 100 basis-point increase in the average rate for CONSOL Energy's and/or CNX Gas' revolving credit facility would have had no affect on net income for the period.

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

Hedging Volumes

As of April 17, 2012 our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2012 Fixed Price Volumes
Hedged Mcf	19,108,632		19,108,632		19,318,617		19,318,617		76,854,498
Weighted Average Hedge Price/Mcf	$	5.25	$	5.25	$	5.25	$	5.25	$	5.25
2013 Fixed Price Volumes
Hedged Mcf	12,513,747		12,652,788		12,791,830		12,791,830		50,750,195
Weighted Average Hedge Price/Mcf	$	5.06	$	5.06	$	5.06	$	5.06	$	5.06
2014 Fixed Price Volumes
Hedged Mcf	10,849,825		10,970,378		11,090,932		11,090,932		44,002,067
Weighted Average Hedge Price/Mcf	$	5.20	$	5.20	$	5.20	$	5.20	$	5.20
2015 Fixed Price Volumes
Hedged Mcf	2,783,505		2,814,433		2,845,361		2,845,361		11,288,660
Weighted Average Hedge Price/Mcf	$	4.03	$	4.03	$	4.03	$	4.03	$	4.03


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 March 31, 2012 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II

OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

The first through the twentieth paragraphs of Note 11—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.


ITEM 6.	EXHIBITS



10.1			CONSOL Energy Inc. Equity Incentive Plan, As Amended and Restated Effective May 1, 2012, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 21, 2012.

10.2			Long-Term Incentive Program (2012-2014).

10.3			Long-Term Incentive Program (2011-2013) (corrected for typographical error).

10.4			Form of Performance Share Unit Award Agreement.

10.5			Seventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 30, 2012, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank.

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.

95			Mine Safety and Health Administration Safety Data.

101			Interactive Data File (Form 10-Q for the quarterly period ended March 31, 2011 furnished in XBRL).

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

SIGNATURES

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

Dated: April 30, 2012



	CONSOL ENERGY INC.

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

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

TABLE OF CONTENTS

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

CNX 10-Q Quarter ended March 31, 2012