10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 __________________________________________________

FORM 10-Q

 __________________________________________________ 

(Mark One)

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

For the quarterly period ended September 30, 2013

OR

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 October 21, 2013
Common stock, $0.01 par value	228,941,697

TABLE OF CONTENTS
		Page
PART I FINANCIAL INFORMATION
ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and nine months ended September 30, 2013 and 2012	3
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012	4
	Consolidated Balance Sheets at September 30, 2013 and December 31, 2012	5
	Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2013	7
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	8
	Notes to Unaudited Consolidated Financial Statements	9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	90
ITEM 4.	Controls and Procedures	92
PART II OTHER INFORMATION
ITEM 1.	Legal Proceedings	93
ITEM 4.	Mine Safety Disclosures	93
ITEM 6.	Exhibits	93

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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Sales—Outside	$	1,160,114		$	1,084,041		$	3,512,055		$	3,584,805
Sales—Gas Royalty Interests	15,506			12,968			46,738			34,707
Sales—Purchased Gas	1,608			953			4,372			2,443
Freight—Outside	11,563			27,430			35,749			126,195
Other Income	42,627			34,697			138,824			293,196
Total Revenue and Other Income	1,231,418			1,160,089			3,737,738			4,041,346
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	851,088			827,530			2,639,929			2,588,460
Gas Royalty Interests Costs	12,864			10,543			38,204			27,916
Purchased Gas Costs	941			737			2,961			2,123
Freight Expense	11,563			27,430			35,749			126,195
Selling, General and Administrative Expenses	33,472			36,681			104,265			109,412
Depreciation, Depletion and Amortization	169,152			153,877			489,774			463,048
Interest Expense	56,301			54,075			164,197			168,788
Taxes Other Than Income	85,463			80,587			251,575			256,543
Total Costs	1,220,844			1,191,460			3,726,654			3,742,485
Earnings (Loss) Before Income Taxes	10,574			(31,371		)	11,084			298,861
Income Taxes	74,623			(19,898		)	89,767			60,428
Net (Loss) Income	(64,049		)	(11,473		)	(78,683		)	238,433
Add: Net Loss Attributable to Noncontrolling Interest	398			105			942			134
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Earnings Per Share:
Basic	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.04
Weighted Average Number of Common Shares Outstanding:
Basic	228,876,336			227,654,395			228,640,671			227,491,284
Dilutive	228,876,336			227,654,395			228,640,671			229,191,870
Dividends Paid Per Share	$	0.125		$	0.125		$	0.250		$	0.375

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

3

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Net (Loss) Income	$	(64,049	)	$	(11,473	)	$	(78,683	)	$	238,433
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($15,422), ($4,775), ($70,161), ($45,242))	24,980			7,921			113,641			75,080
Net Increase (Decrease) in the Value of Cash Flow Hedges (Net of tax: ($8,536), $4,161, ($26,036), ($51,716))	13,246			(6,459		)	40,400			80,280
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $14,025, $29,683, $36,551, $97,760)	(24,354		)	(47,809		)	(56,595		)	(153,597		)
Other Comprehensive Income (Loss)	13,872			(46,347		)	97,446			1,763
Comprehensive (Loss) Income	(50,177		)	(57,820		)	18,763			240,196
Add: Comprehensive Loss Attributable to Noncontrolling Interest	398			105			942			134
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(49,779	)	$	(57,715	)	$	19,705		$	240,330

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

4

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	(Unaudited)
	September 30, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and Cash Equivalents	$	21,086	$	21,878
Accounts and Notes Receivable:
Trade	436,388		428,328
Notes Receivables	25,813		318,387
Other Receivables	160,931		131,131
Accounts Receivable - Securitized	44,364		37,846
Inventories	238,348		247,766
Deferred Income Taxes	81,825		148,104
Restricted Cash	12,263		48,294
Prepaid Expenses	162,418		157,360
Total Current Assets	1,183,436		1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	16,571,104		15,545,204
Less—Accumulated Depreciation, Depletion and Amortization	5,940,247		5,354,237
Total Property, Plant and Equipment—Net	10,630,857		10,190,967
Other Assets:
Deferred Income Taxes	457,105		444,585
Restricted Cash	—		20,379
Investment in Affiliates	261,218		222,830
Notes Receivable	155		25,977
Other	204,301		227,077
Total Other Assets	922,779		940,848
TOTAL ASSETS	$	12,737,072	$	12,670,909

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

5

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

	(Unaudited)
	September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	512,182		$	507,982
Current Portion of Long-Term Debt	13,182			13,485
Short-Term Notes Payable	47,000			25,073
Accrued Income Taxes	87,965			34,219
Borrowings Under Securitization Facility	44,364			37,846
Other Accrued Liabilities	868,904			768,494
Total Current Liabilities	1,573,597			1,387,099
Long-Term Debt:
Long-Term Debt	3,123,755			3,124,473
Capital Lease Obligations	48,176			50,113
Total Long-Term Debt	3,171,931			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	2,814,234			2,832,401
Pneumoconiosis Benefits	178,508			174,781
Mine Closing	460,515			446,727
Gas Well Closing	197,093			148,928
Workers’ Compensation	156,568			155,648
Salary Retirement	74,108			218,004
Reclamation	49,487			47,965
Other	103,855			131,025
Total Deferred Credits and Other Liabilities	4,034,368			4,155,479
TOTAL LIABILITIES	8,779,896			8,717,164
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,936,248 Issued and Outstanding at September 30, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012	2,292			2,284
Capital in Excess of Par Value	2,347,973			2,296,908
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,257,796			2,402,551
Accumulated Other Comprehensive Loss	(649,896		)	(747,342		)
Common Stock in Treasury, at Cost— No Shares at September 30, 2013 and 34,755 Shares at December 31, 2012	—			(609		)
Total CONSOL Energy Inc. Stockholders’ Equity	3,958,165			3,953,792
Noncontrolling Interest	(989		)	(47		)
TOTAL EQUITY	3,957,176			3,953,745
TOTAL LIABILITIES AND EQUITY	$	12,737,072		$	12,670,909

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

6

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)

	Common Stock		Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
December 31, 2012	$	2,284	$	2,296,908		$	2,402,551		$	(747,342	)	$	(609	)	$	3,953,792		$	(47	)	$	3,953,745
(Unaudited)
Net Loss	—		—			(77,741		)	—			—			(77,741		)	(942		)	(78,683		)
Other Comprehensive Income	—		—			—			97,446			—			97,446			—			97,446
Comprehensive (Loss) Income	—		—			(77,741		)	97,446			—			19,705			(942		)	18,763
Issuance of Common Stock	8		2,690			—			—			—			2,698			—			2,698
Treasury Stock Activity	—		—			(9,803		)	—			609			(9,194		)	—			(9,194		)
Tax Cost From Stock-Based Compensation	—		(2,539		)	—			—			—			(2,539		)	—			(2,539		)
Amortization of Stock-Based Compensation Awards	—		50,914			—			—			—			50,914			—			50,914
Dividends ($0.250 per share)	—		—			(57,211		)	—			—			(57,211		)	—			(57,211		)
Balance at September 30, 2013	$	2,292	$	2,347,973		$	2,257,796		$	(649,896	)	$	—		$	3,958,165		$	(989	)	$	3,957,176

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

7

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended
	September 30,
	2013			2012
Operating Activities:
Net (Loss) Income	$	(78,683	)	$	238,433
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	489,774			463,048
Stock-Based Compensation	50,914			38,423
Gain on Sale of Assets	(52,794		)	(190,257		)
Amortization of Mineral Leases	2,014			3,818
Deferred Income Taxes	(31,099		)	(5,225		)
Equity in Earnings of Affiliates	(20,276		)	(22,676		)
Changes in Operating Assets:
Accounts and Notes Receivable	11,145			13,359
Inventories	9,418			(8,204		)
Prepaid Expenses	(9,259		)	(1,362		)
Changes in Other Assets	24,318			(8,961		)
Changes in Operating Liabilities:
Accounts Payable	(20,553		)	5,218
Other Operating Liabilities	174,740			(11,130		)
Changes in Other Liabilities	8,148			1,469
Other	31,198			14,210
Net Cash Provided by Operating Activities	589,005			530,163
Investing Activities:
Capital Expenditures	(1,195,909		)	(1,152,021		)
Change in Restricted Cash	56,410			—
Proceeds from Sales of Assets	598,174			583,942
Net Investments In Equity Affiliates	(18,112		)	(18,701		)
Net Cash Used in Investing Activities	(559,437		)	(586,780		)
Financing Activities:
Proceeds from Short-Term Borrowings	47,000			—
Payments on Miscellaneous Borrowings	(32,290		)	(6,565		)
Proceeds from Securitization Facility	6,518			—
Tax Benefit from Stock-Based Compensation	2,316			2,578
Dividends Paid	(57,211		)	(85,290		)
Issuance of Common Stock	2,698			1,234
Issuance of Treasury Stock	609			109
Debt Issuance and Financing Fees	—			(227		)
Net Cash Used In Financing Activities	(30,360		)	(88,161		)
Net Decrease in Cash and Cash Equivalents	(792		)	(144,778		)
Cash and Cash Equivalents at Beginning of Period	21,878			375,736
Cash and Cash Equivalents at End of Period	$	21,086		$	230,958

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

8

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2012 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, 2012 included in CONSOL Energy Inc.'s Form 10-K.

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2012, with no effect on previously reported net income or stockholders' equity.

Basic earnings per share are computed by dividing net (loss) income attributable to shareholders 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, performance stock options, and CONSOL share units, 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, performance share options, and CONSOL share units were exercised, that outstanding restricted stock units 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 September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Anti-Dilutive Options	4,833,174	5,740,444	4,833,174	2,412,502
Anti-Dilutive Restricted Stock Units	1,243,207	1,348,046	1,243,207	13,302
Anti-Dilutive Performance Share Units	97,142	488,179	97,142	—
Anti-Dilutive Performance Share Options	602,101	501,744	602,101	501,744
	6,775,624	8,078,413	6,775,624	2,927,548

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Options	11,655	108,477	256,768	159,611
Restricted Stock Units	130,523	22,025	698,664	548,492
Performance Share Units	—	—	159,228	229,730
	142,178	130,502	1,114,660	937,833

The weighted average exercise price per share of the options exercised during the three months ended September 30, 2013 and 2012 was $17.40 and $7.13, respectively. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2013 and 2012 was $10.49 and $8.39, respectively.

9

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Weighted average shares of common stock outstanding:
Basic	228,876,336			227,654,395			228,640,671			227,491,284
Effect of stock-based compensation awards	—			—			—			1,700,586
Dilutive	228,876,336			227,654,395			228,640,671			229,191,870
Earnings per share:
Basic	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.04

Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows:

	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	40,400			61,912			102,312
Amounts reclassified from accumulated other comprehensive income	(56,595		)	51,729			(4,866		)
New current period other comprehensive income	(16,195		)	113,641			97,446
Balance at September 30, 2013	$	60,566		$	(710,462	)	$	(649,896	)

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Derivative Instruments (Note 12)
Natural gas price swaps	$	(38,379	)	$	(77,492	)	$	(93,146	)	$	(251,357	)
Tax benefit	14,025			29,683			36,551			97,760
Net of tax	$	(24,354	)	$	(47,809	)	$	(56,595	)	$	(153,597	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(8,212	)	$	(13,915	)	$	(24,635	)	$	(39,937	)
Recognized net actuarial loss	21,055			26,611			69,802			79,688
Settlement loss	6,296			—			38,498			—
Total	19,139			12,696			83,665			39,751
Tax expense	(7,306		)	(4,775		)	(31,936		)	(14,946		)
Net of tax	$	11,833		$	7,921		$	51,729		$	24,805

*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the three months and nine months ended September 30, 2013 and September 30, 2012.

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In September 2013, CONSOL Energy completed the sale of 1.5 MM tons of reserves of Pittsburgh 8 Coal in Belmont County, Ohio. The sale of this coal was structured as a $2,300 payment upfront and then a 3% overriding royalty paid as the coal is being mined. A gain of $2,300 was included in Other Income in the Consolidated Statement of Income.

10

In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24,764 of which $12,263 was restricted, pending release by the Canadian Revenue Authority upon review of the tax consequences of the transaction. A gain of $15,260 was included in Other Income in the Consolidated Statement of Income.

In June 2013, CONSOL Energy completed the sale of Potomac coal reserves in Grant and Tucker Counties in West Virginia. Cash proceeds for the sale were $25,000. A gain of $24,663 was included in Other Income in the Consolidated Statement of Income.    

In May 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Robinson Run Mine. Cash proceeds for the sale were $68,337. A loss of $236 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

In April 2013, the Company and the Commonwealth of Pennsylvania (Commonwealth) entered into a Settlement Agreement and Release settling all of the Commonwealth's claims regarding the Ryerson Park Dam (Dam) and the Ryerson Park Lake (Lake).   The Settlement provides in part for the payment to the Commonwealth of $36,000 for use to rebuild the Dam and restore the Lake with $13,728 of the settlement amount credited to lease bonus and royalty payments on the Commonwealth's Marcellus gas interests within the Park, subject to the Company's agreement to extract the gas from surface facilities located outside of the boundaries of the Park.  The Settlement also provides in part for the conveyance by the Company to the Commonwealth of eight surface parcels containing approximately 506 acres of land adjoining the Park after the parcels are no longer needed for the Company's operations and the conveyance by the Commonwealth to the Company of certain coal and mining rights in an area of the Bailey Mine where a mining permit application is currently pending.

In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres.  A majority of these contiguous acres are in the liquids area of the Marcellus Shale play.  CNX Gas Company paid $46,315 as an up-front bonus payment at closing.  Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title.  CNX Gas Company must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company forgoes the bonus. Our joint venture partner, Noble Energy Inc., has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs during the nine months ended September 30, 2013.

In March 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Shoemaker Mine. Cash proceeds for the sale were $63,839. A loss of $279 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

In January 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $71,166. A loss of $358 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

On December 21, 2012, CONSOL Energy completed the disposition of its non-producing Ram River & Scurry Ram assets in Western Canada which consisted of 36 thousand acres of coal lands. In December 2012, cash proceeds of $51,869, of which $48,294 was restricted, were received related to this transaction. These proceeds were net of $637 in transaction fees. The restrictions on the cash were removed during the three months ended March 31, 2013 and are reflected as a Change in Restricted Cash in the Investing section of the Consolidated Statement of Cash Flows. Additionally, a note receivable was recognized in 2012 related to the two additional cash payments to be received in June 2013 and June 2014. Payment of $25,500 was received in June 2013. A note receivable of $24,500 was included in Accounts and Notes Receivables - Notes Receivables in the Consolidated Balance Sheet at September 30, 2013. The second payment is due June 2014. The gain on the transaction was $89,943 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On June 29, 2012, CONSOL Energy completed the disposition of its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for cash proceeds of $169,500. The assets consisted of CONSOL Energy's 50% interest in Youngs Creek Mining Company LLC, CONSOL Energy's 50% interest in CX Ranch and related properties in and around Sheridan, Wyoming. The gain on the transaction was $150,677 and was included in Other Income in the Consolidated Statement

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of Income for the year ended December 31, 2012. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal.

On April 4, 2012, CONSOL Energy completed the disposition of its non-producing Elk Creek property in southern West Virginia, which consisted of 20 thousand acres of coal lands and surface rights, for proceeds of $26,000. The gain on the transaction was $11,235 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property in Illinois, 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 was included in Other Income in the Consolidated Statements of Income for the year ended December 31, 2012.

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

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

	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	4,897		$	5,527		$	16,184		$	15,530		$	4,849		$	4,525		$	14,547		$	14,291
Interest cost	9,497			9,396			27,249			28,190			29,619			33,687			88,856			102,008
Expected return on plan assets	(13,336		)	(11,538		)	(38,191		)	(34,617		)	—			—			—			—
Amortization of prior service credits	(408		)	(408		)	(1,223		)	(1,223		)	(7,804		)	(13,409		)	(23,411		)	(38,418		)
Recognized net actuarial loss	8,042			11,959			30,764			35,876			17,595			20,255			52,784			60,620
Settlement loss	6,296			—			38,498			—			—			—			—			—
Net periodic benefit cost	$	14,988		$	14,936		$	73,281		$	43,756		$	44,259		$	45,058		$	132,776		$	138,501

For the nine months ended September 30, 2013, $55,272 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 2013. CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Net periodic benefit costs are allocated to Costs of Goods Sold and Other Operating Charges and Selling, General and Administrative Expenses in the Consolidated Statements of Income.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three and nine months ended September 30, 2013. Accordingly, CONSOL Energy recognized expense of $6,296 and $38,498 for the three and nine months ended September 30, 2013, respectively, in Costs of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement charges noted above also resulted in a remeasurement of the pension plan at September 30, June 30, and March 31, 2013. The September 30, 2013 remeasurement resulted in a change to the discount rate to 4.80% from 4.84% at June 30, 2013. The September remeasurement reduced the pension liability by $21,264. The September settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $17,040 in Other Comprehensive Income, net of $10,520 in deferred taxes. It is reasonably possible that CONSOL Energy will incur additional settlement charges in 2013, which would require the pension plan to be remeasured using updated assumptions.

CONSOL Energy does not expect to contribute to the other post-employment benefit plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $124,504 of other post-employment benefits have been paid.

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

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

	CWP												Workers' Compensation
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2,135		$	1,927		$	6,405		$	5,783		$	3,533		$	3,634		$	10,599		$	10,903
Interest cost	1,808			1,991			5,424			5,973			1,655			1,778			4,966			5,335
Amortization of actuarial gain	(4,213		)	(4,933		)	(12,638		)	(14,799		)	(699		)	(986		)	(2,098		)	(2,958		)
State administrative fees and insurance bond premiums	—			—			—			—			1,496			1,795			4,500			5,340
Legal and administrative costs	—			—			—			—			591			648			1,773			1,943
Net periodic (benefit) cost	$	(270	)	$	(1,015	)	$	(809	)	$	(3,043	)	$	6,576		$	6,869		$	19,740		$	20,563

CONSOL Energy does not expect to contribute to the CWP plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $7,879 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $21,271 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

The effective tax rate for the nine months ended September 30, 2013 and 2012 was 809.9% and 20.2%, respectively.

The rate for the nine months ended September 30, 2013 differs from the U.S. federal statutory rate of35% primarily due to a $111,104 income tax charge for excess depletion, $4,701 discrete income tax charge related to the gain on the sale of the Potomac coal reserves, $8,467 discrete income tax charge related to the gain on the sale of the Crowsnest Pass coal reserves, and a $1,585 income tax benefit due to a refund claim related to prior year Commonwealth of Pennsylvania taxes.

For the three months ended September 30, 2013, CONSOL Energy recognized additional tax expense as a result of changes in estimates of percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision. The result of these changes was a tax increase of $5,875.

The rate for the nine months ended September 30, 2012 differs from the U.S. federal statutory rate of 35% primarily due to a $53,932 benefit recorded for excess depletion, $48,976discrete income tax charge related to the gain on the sale of non-producing North Powder River Basin assets, $983discrete income tax reduction related to a successful resolution with the Internal Revenue Service Appeals Division of the company’s Extraterritorial Income Exclusion refund claims for tax years 2004 and 2005, and $1,786discrete income tax reduction related to the successful resolution of an audit with the Canadian Revenue Agency.

For the three months ended September 30, 2012, CONSOL Energy recognized additional tax expense as a result of changes in estimates of percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision. The result of these changes was a tax increase of $6,004.

The total amounts of uncertain tax positions at September 30, 2013 and 2012 were $22,770 and $25,570, respectively. If these uncertain tax positions were recognized, approximately $2,071 and $3,891, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the nine months ended September 30, 2013 and 2012.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of September 30, 2013 and 2012, the Company reported an accrued interest liability relating to uncertain tax positions of $5,851 and $7,095, respectively. The accrued interest liability includes $1,020 and $1,722 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2013 and 2012, respectively.

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CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of September 30, 2013 and 2012, 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:

	September 30, 2013		December 31, 2012
Coal	$	58,050	$	78,825
Merchandise for resale	37,792		35,363
Supplies	142,506		133,578
Total Inventories	$	238,348	$	247,766

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, and other related costs.

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $18,683 and $19,700 at September 30, 2013 and December 31, 2012, 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 September 30, 2013, there were letters of credit outstanding against the facility of $155,636. CONSOL Energy management believes that these letters of credit will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's 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 or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $416 and $1,328 for three and nine months ended September 30, 2013, respectively. Costs associated with the receivables facility totaled $420 and $1,276 for three and nine months ended September 30, 2012, 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.

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At September 30, 2013 and December 31, 2012, eligible accounts receivable totaled $200,000. There was no subordinated retained interest at September 30, 2013 and at December 31, 2012. There were $44,364 of borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of September 30, 2013 and $37,846 at December 31, 2012. The accounts receivable securitization program increased $6,518 in the nine months ended September 30, 2013 and there was no change in the nine months ended September 30, 2012. The increase is reflected in the Net Cash Used in Financing Activities in the Consolidated Statement of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:

	September 30, 2013		December 31, 2012
Coal and other plant and equipment	$	6,207,105	$	6,030,620
Intangible drilling cost	1,830,666		1,550,297
Proven gas properties	1,601,106		1,596,838
Coal properties and surface lands	1,449,526		1,346,151
Unproven gas properties	1,383,921		1,266,017
Gas gathering equipment	1,046,495		1,006,882
Airshafts	746,134		706,388
Mine development	608,630		537,939
Leased coal lands	529,409		529,758
Gas wells and related equipment	623,176		492,367
Coal advance mining royalties	397,015		391,501
Other gas assets	125,635		82,217
Gas advance royalties	22,286		8,229
Total Property Plant and Equipment	16,571,104		15,545,204
Less: Accumulated DD&A	5,940,247		5,354,237
Total Net PP&E	$	10,630,857	$	10,190,967

Industry Participation Agreements

CONSOL Energy has two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for our retained interests.

On October 21, 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which were net of $5,719 in 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 aggregate amount of the drilling carry can be adjusted downward under provisions of the joint venture agreements in certain events. The net gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. CONSOL Energy and Hess have agreed to focus their development efforts on six core counties in southeastern Ohio, in which the joint venture holds approximately 73,000 mostly fee acres. To this end, the parties have agreed to pursue the sale of approximately 63,000 acres outside of the focus areas. In addition, as previously announced, based on title work performed by Hess as part of the title defect process, we believe that there are chain of title issues with respect to approximately 39,000 of the joint venture acres representing approximately $153,000 of carry, most of which likely cannot be cured. These acres, together with another 26,000 acres of allegedly defective acres will be reassigned to CONSOL Energy. CONSOL Energy may elect to cure the alleged defects related to these acres and develop them, or sell the acres for its own account. After taking into account the reassignment of approximately 65,000 acres, the parties have agreed that the total carry remaining after these adjustments is $335,000. The loss of these Utica Shale acres will not have a material impact on the Company's financial statements.  

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

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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 September 2013, cash proceeds of $327,964 were received related to the second anniversary note receivable. In September 2012, cash proceeds of $327,964 were received related to the first anniversary note receivable. During December 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. Adjusted cash proceeds of $15,598 related to the additional receivable were received in April 2012. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 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 is currently suspended and 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 aggregate amount of the drilling carry may also be adjusted downward under provisions of the joint venture agreements in certain events.

Under our joint venture agreement with Noble, Noble had the right to perform due diligence on the title to the oil and gas interests which CONSOL Energy conveyed to them and to assert that title to the acreage is defective. CONSOL Energy then can review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party can submit the defect to an arbitrator for resolution. The Company has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, the Company has addressed defects with respect to approximately 86.498 gross deal acres, having a carry value of approximately $543,000, to the satisfaction of both parties. Noble has asserted title defects with respect to approximately 2,868 gross deal acres, having a carry value of approximately $27,000, which have not yet been addressed to the full satisfaction of both parties. The Company is working closely with Noble to address these remaining and final alleged defects. To date, the Company has conceded defects which have an aggregate value of approximately $204,000 in excess of the applicable deductibles. The impact of these conceded defects was $12,983 and $21,763 of expense for the three and nine months ended September 30, 2013 and was included in Cost of Goods Sold and Other Charges in the Consolidated Statement of Income. CONSOL Energy and Noble made a concerted effort during the quarter to address the remaining title defects, which resulted in a higher write-off of defected acres than in prior quarters; however, as a result of this effort, the parties have resolved substantially all outstanding asserted defects and any final write-off in the fourth quarter is not expected to be material.

The following table provides information about our industry participation agreements as of September 30, 2013:

Shale Play	Industry Participation Agreement Partner	Industry Participation Agreement Date	Drilling Carries Remaining*
Marcellus	Noble Energy, Inc.	September 30, 2011	$	1,885,785
Utica	Hess Ohio Developments, LLC	October 21, 2011	$	255,148

*See above for a description of the impact on the drilling carries of title defects that have been asserted by Noble.

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 (Adjusted 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 3.96 to 1.00 at September 30, 2013. The facility includes a maximum leverage ratio covenant of no more than 4.50 to 1.00, measured quarterly. The leverage ratio was 3.21 to 1.00 at September 30, 2013. 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 0.11 to 1.00 at September 30, 2013. 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 September 30, 2013, the $1,500,000 facility had no borrowings outstanding and $104,137 of letters of credit outstanding, leaving $1,395,863 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the $1,500,000 facility had no borrowings outstanding and $100,292 of letters of credit outstanding, leaving $1,399,708 of capacity available for borrowings and the issuance of letters of credit.

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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 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 CONE Gathering, LLC (CONE) 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 0.75 to 1.00 at September 30, 2013. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 28.55 to 1.00 at September 30, 2013. At September 30, 2013, the $1,000,000 facility had $47,000 borrowings outstanding and $70,051 of letters of credit outstanding, leaving $882,949 of capacity available for borrowings and the issuance of letters of credit. At December 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 average interest rate for the three months and nine months ended September 30, 2013 was 1.80% and 1.76%, respectively. Accrued interest of $5 and $29 was included in Other Accrued Liabilities in the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012, respectively.

CONSOL Energy entered into an interim funding arrangement for longwall shields. At December 31, 2012, CONSOL

Energy had a note payable of $25,073 related to this funding arrangement. The interim funding arrangement bore a weighted average interest rate of 2.46% as of December 31, 2012. There were no interim funding agreements outstanding at September 30, 2013.

NOTE 10—LONG-TERM DEBT:

	September 30, 2013		December 31, 2012
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
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.43% weighted average interest rate for September 30, 2013 and December 31, 2012)	20,394		20,394
Other long-term notes maturing at various dates through 2031 (total value of $6,268 and $7,300 less unamortized discount of $1,166 and $1,542 at September 30, 2013 and December 31, 2012, respectively).	5,102		5,758
	3,128,361		3,129,017
Less amounts due in one year *	4,606		4,544
Long-Term Debt	$	3,123,755	$	3,124,473

* Excludes current portion of Capital Lease Obligations of $8,576 and $8,941 at September 30, 2013 and December 31, 2012, respectively.

Accrued interest related to Long-Term Debt of $113,589 and $63,363 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2013 and December 31, 2012, 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 amounts 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

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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 $792,000.

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. The AOC was signed on July 20, 2012, and as a result, the EPA granted 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%. In 2011, CONSOL Energy established an initial accrual based on its allocated share of the costs among the viable former customers of American Electric Corp. During the year ended December 31, 2012, CONSOL Energy funded $250 to an independent trust established for the remediation, which is 50% of CONSOL Energy's allocated share of the trust fund. The liability is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the 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 and in September 2008, the EPA notified CONSOL Energy and 60 other companies that they are PRPs for these additional areas. 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 $12,800. CONSOL Energy recognized $576 in expense in Cost of Goods Sold and Other charges in the nine months ended September 30, 2013 and recognized no expense in the nine months ended September 30, 2012. Also, CONSOL Energy has provided funding to an independent trust established for this remediation. CONSOL Energy funded $2,563 in the nine months ended September 30, 2013 and funded $400 in the nine months ended September 30, 2012. As of September 30, 2013, 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 $3,805. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at September 30, 2013 is $1,769.

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

South Carolina Electric & Gas Company Arbitration: In April, 2009, South Carolina Electric & Gas Company (SCE&G), a public utility, filed an arbitration complaint, against CONSOL of Kentucky Inc. and CONSOL Energy Sales

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Company, both wholly owned subsidiaries of CONSOL Energy, seeking $36,000 in damages. SCE&G claimed it suffered those 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, alleging that SCE&G had agreed that shortfalls could be made up in 2009.  A four day hearing on the claims commenced on April 30, 2012. On December 21, 2012, the Arbitration Panel awarded SCE&G $9,735, plus interest at 8.75% from January 9, 2011, and attorney fees. The Award is against CONSOL of Kentucky only. On August 14, 2013, the Panel, over vigorous objection by CONSOL, awarded SCE&G $1,232 for attorneys’ fees and expenses. We had established an accrual to cover our estimated liability for this case, and have paid the final award in the nine months ended September 30, 2013. This matter is now concluded.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company, et. al. The lawsuit alleges that the plaintiff class consists of forced-pooled unleased gas owners whose gas ownership is in conflict, the Virginia Supreme Court and General Assembly have decided that coalbed methane (CBM) belongs to the owner of the gas estate, the Virginia Gas and Oil Act of 1990 unconstitutionally provides only a 1/8 net proceeds royalty to CBM owners for gas produced under the forced-pooled orders, and CNX Gas Company relied upon control of only the coal estate in force pooling the CBM notwithstanding decisions by the Virginia Supreme Court. 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 lawsuit also alleges CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed 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. 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. The Magistrate Judge recommended against the dismissal of certain other claims. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An amended complaint was filed, which added additional allegations that include gas hedging receipts should have been used as the basis for royalty payments, severance tax should not be allowed as a post-production deduction from royalties, and damages incurred because gas was produced prior to the entry of pooling orders. A motion to dismiss the Amended Complaint was filed and denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a Rule 23 class action and intends to appeal the class certification Order to the U.S. Court of Appeals for the Fourth Circuit. Discovery is proceeding in this litigation. CONSOL Energy believes that the case has meritorious defenses 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al.  The lawsuit alleges that the plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit alleges that the Virginia Supreme Court and General Assembly have decided that the plaintiff owns the gas and is entitled to royalties held in escrow by the Commonwealth of Virginia or CNX Gas Company. The lawsuit also alleges 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. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breach of fiduciary duties; and unjust enrichment. The Magistrate Judge issued a Report and Recommendation recommending dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An Amended Complaint was filed which added an additional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and was denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a Rule 23 class action and intends to appeal the class certification Order to the U.S. Court of Appeals for the Fourth Circuit. Discovery is proceeding in this litigation. CONSOL Energy believes that the case has meritorious defenses 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

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

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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 two cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL).  (A third case filed in Delaware was voluntarily dismissed by the plaintiff in 2010.) All four 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. Following a mediation, the parties to the Delaware litigation have agreed in principle to a settlement and release of all of the claims of the plaintiff class (as defined in a January 20, 2011 order of certification) in exchange for defendants' agreement to establish a settlement fund in the amount of $42,730 for distribution to class members, of which CONSOL Energy is responsible for $19,200. On May 8, 2013, the parties executed and filed with the Court a Stipulation and Agreement of Compromise and Settlement. A Settlement Hearing was held by the Court on August 23, 2013, and the settlement was approved. There were no appeals, and the settlement was paid in October 2013.

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

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 Litigation: On March 22, 2012, the Company was served with four complaints filed on May 31, 2011 by four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, subsidiaries of CONSOL Energy, as well as CONSOL Energy itself in the Circuit Court of Russell County, Virginia. The complaints seek damages and injunctive relief in connection with the deposit of water from mining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits allege damage to coal and coalbed methane and seek recovery in tort, contract and assumpsit (quasi-contract). The cases were removed to federal court, motions to dismiss were filed by CCC, and then were voluntarily dismissed by the plaintiffs. On January 30, 2013, the four plaintiffs filed a single consolidated complaint against the same defendants in the United States District Court for the Western District of Virginia, alleging the same damage and theories of recovery for storage of water in the mine voids ostensibly underlying their property. The suit seeks damages ranging from $4,000 to $8,000 plus punitive damages. Service was effected on April 1, 2013 by waiver. A Motion to Dismiss Plaintiffs' Complaint and, in the Alternative, Motion for More Definitive Statement was filed by the defendants on May 31, 2013. Plaintiffs' Response in opposition to the Motion to Dismiss was filed on June 20, 2013, and the defendants on July 1, 2013, filed their Reply to the Response. Plaintiffs filed a Sur Reply brief on July 8, 2013, for the first time arguing the interpretation of the Virginia Mine Void Statute urged by defendants was unconstitutional. Based on Plaintiffs’ challenge, the Court on August 1, 2013, entered a Certificate pursuant to 28 USC Section 2304 notifying the Virginia Attorney General that the Mine Void Statute had been called into question and advising the Commonwealth of its right to intervene in the proceedings for the limited purpose of addressing the constitutionality of the statute. To date, the Virginia Attorney General has not responded. CONSOL Energy intends to vigorously defend the suit.

Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court.  The named plaintiff is Earl D. Hall.  The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy.  The complaint alleges more than 1,000 similarly situated lessors.  The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying royalties on oil production. The complaint also alleges that royalty statements were false and misleading.  The complaint seeks damages, interest and an accounting on a well-by-well basis. The case has been inactive since December 2011. 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.

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    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 ruled for CNX Gas Company and CONSOL Energy, holding that the “roof/rider” coal is included in the Pittsburgh 8 coal seam. The plaintiffs have indicated that they intend to appeal that decision. A trial on the issue of whether a drilling that deviates from the coal seam results in damage to the gas owner is anticipated for first quarter 2014. 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 Inc., 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 farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources 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 Resources' 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/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently been permitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A motion to dismiss will be filed. Initial mediation efforts have been unsuccessful. A Status Conference and hearing on pending discovery motions has been scheduled by the Court for November 6, 2013. 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. Discovery is proceeding in this litigation. 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. (Comer I). 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 (Comer II). The trial court dismissed this case, and the dismissal was appealed. On May 14, 2013, a panel of the U.S. Court of Appeals for the Fifth Circuit affirmed, holding res judicata arising from Comer I bars the plaintiffs' claims in Comer II. On June 5, 2013, the Fifth Circuit issued its mandate. August 12, 2013, was the deadline by which Plaintiffs had to file a certiorari petition with the Supreme Court of the United States. They did not do so. This matter is now concluded.

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At September 30, 2013, 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	$	190,358	$	71,624	$	118,734	$	—	$	—
Environmental	56,294		54,566		1,728		—		—
Other	83,246		34,488		48,758		—		—
Total Letters of Credit	329,898		160,678		169,220		—		—
Surety Bonds:
Employee-Related	204,884		204,884		—		—		—
Environmental	537,167		495,017		42,150		—		—
Other	31,955		31,719		235		—		1
Total Surety Bonds	774,006		731,620		42,385		—		1
Total Commitments	$	1,103,904	$	892,298	$	211,605	$	—	$	1

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state and federal 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 September 30, 2013, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due	Amount
Less than 1 year	$	393,709
1 - 3 years	253,025
3 - 5 years	189,138
More than 5 years	419,240
Total Purchase Obligations	$	1,255,112

Costs related to these purchase obligations include:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Major equipment purchases	$	8,990	$	59,799	$	57,571	$	104,980
Firm transportation expense	29,654		18,844		89,196		49,711
Gas drilling obligations	26,296		27,100		81,419		85,192
Other	—		65		—		492
Total costs related to purchase obligations	$	64,940	$	105,808	$	228,186	$	240,375

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NOTE 12—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. 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 the fair value of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets and reclassified into Outside Sales on the Consolidated Statements of Income 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.

None of our counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL Energy would have to post collateral for hedges in a liabilities position in excess of defined thresholds. All of our derivative instruments are subject to master netting arrangements with our counterparties.  CONSOL Energy recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.

                Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL Energy and the applicable counterparty would net settle all open hedge positions.

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of September 30, 2013, the total notional amount of the Company’s outstanding natural gas swap contracts was 216.5 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $44,438 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Outside Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at September 30, 2013 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $107,366 and a liability of $5,252. The total asset is comprised of $75,735 and $31,631 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $746 and $4,506 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The gross fair value at December 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $135,969 and a liability of $7,024. The total asset is comprised of $80,057 and $55,912 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $970 and $6,054 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

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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:

	For the Three Months Ended September 30,
	2013		2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	71,674	$	132,731
Gain/(Loss) recognized in Accumulated OCI	$	13,246	$	(6,459	)
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	24,354	$	47,809
Ending Balance – Accumulated OCI	$	60,566	$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	2,592	$	1,732

	For the Nine Months Ended September 30,
	2013			2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	76,761		$	151,780
Gain/(Loss) recognized in Accumulated OCI	$	40,400		$	80,280
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	56,595		$	153,597
Ending Balance – Accumulated OCI	$	60,566		$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(120	)	$	1,778

There were no amounts excluded from the assessment of hedge effectiveness in 2013 or 2012.

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 September 30, 2013						Fair Value Measurements at December 31, 2012
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	$	—	$	102,114	$	—	$	—	$	128,945	$	—

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

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

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

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

Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair 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.

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

	September 30, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	21,086		$	21,086		$	21,878		$	21,878
Restricted Cash (a)	$	12,263		$	12,263		$	68,673		$	68,673
Short-Term Notes Payable	$	(47,000	)	$	(47,000	)	$	(25,073	)	$	(25,073	)
Borrowings Under Securitization Facility	$	(44,364	)	$	(44,364	)	$	(37,846	)	$	(37,846	)
Long-Term Debt	$	(3,128,361	)	$	(3,320,618	)	$	(3,129,017	)	$	(3,378,058	)

(a) The 2013 restricted cash balance of $12,263 was included in current assets of the Consolidated Balance Sheet. The 2012 restricted cash balance includes $48,294 and $20,379 included in current assets and other assets of the Consolidated Balance Sheet, respectively.

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 thermal 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 nine months ended September 30, 2013, 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 nine months ended September 30, 2013, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the nine months ended September 30, 2013, 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.

Annually, the preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2012 gas reserve results, which are reported in the Supplemental Gas Data year ended December 31, 2012 Form 10-K, were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer in the state of Texas with over 14 years of experience in the oil and gas industry.

25

Industry segment results for the three months ended September 30, 2013 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	$	753,692	$	98,232	$	29,608	$	7,470		$	889,002	$	83,269	$	72,406	$	32,957		$	4,150		$	192,782		$	78,330		$	—		$	1,160,114	(A)
Sales—purchased gas	—		—		—		—			—		—		—		—			1,608			1,608			—			—			1,608
Sales—gas royalty interests	—		—		—		—			—		—		—		—			15,506			15,506			—			—			15,506
Freight—outside	—		—		—		11,563			11,563		—		—		—			—			—			—			—			11,563
Intersegment transfers	—		—		—		—			—		—		—		—			601			601			32,213			(32,814		)	—
Total Sales and Freight	$	753,692	$	98,232	$	29,608	$	19,033		$	900,565	$	83,269	$	72,406	$	32,957		$	21,865		$	210,497		$	110,543		$	(32,814	)	$	1,188,791
Earnings (Loss) Before Income Taxes	$	128,112	$	21,295	$	6,466	$	(70,068	)	$	85,805	$	20,909	$	27,941	$	(2,124	)	$	(48,593	)	$	(1,867	)	$	(6,991	)	$	(66,373	)	$	10,574	(B)
Segment assets										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(C)
Depreciation, depletion and amortization										$	104,530											$	58,444		$	6,178		$	—		$	169,152
Capital expenditures										$	156,730											$	273,474		$	7,705		$	—		$	437,909

(A)    Included in the Coal segment are sales of $164,572 to First Energy and $119,707 to Xcoal Energy & Resources each comprising over 10% of sales.

(B)     Includes equity in earnings of unconsolidated affiliates of $(1,682), $5,307 and $(16) for Coal, Gas and All Other, respectively.

(C)    Includes investments in unconsolidated equity affiliates of $20,131, $183,895 and $57,192 for Coal, Gas and All Other, respectively.

26

Industry segment results for the three months ended September 30, 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	$	667,372	$	110,239	$	48,484	$	5,214		$	831,309	$	94,169	$	36,253	$	32,288		$	2,392		$	165,102	$	87,630	$	—		$	1,084,041		(D)
Sales—purchased gas	—		—		—		—			—		—		—		—			953			953		—		—			953
Sales—gas royalty interests	—		—		—		—			—		—		—		—			12,968			12,968		—		—			12,968
Freight—outside	—		—		—		27,430			27,430		—		—		—			—			—		—		—			27,430
Intersegment transfers	—		—		—		—			—		—		—		—			345			345		37,987		(38,332		)	—
Total Sales and Freight	$	667,372	$	110,239	$	48,484	$	32,644		$	858,739	$	94,169	$	36,253	$	32,288		$	16,658		$	179,368	$	125,617	$	(38,332	)	$	1,125,392
Earnings (Loss) Before Income Taxes	$	89,743	$	42,722	$	9,640	$	(134,301	)	$	7,804	$	30,983	$	6,347	$	(3,439	)	$	(22,227	)	$	11,664	$	8,494	$	(59,333	)	$	(31,371	)	(E)
Segment assets										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594		(F)
Depreciation, depletion and amortization										$	95,702											$	52,215	$	—	$	5,960		$	153,877
Capital expenditures										$	254,864											$	166,617	$	16,141	$	—		$	437,622

(D) Included in the Coal segment are sales of $129,014 to First Energy which comprises over 10% of sales.

(E) Includes equity in earnings of unconsolidated affiliates of $(3,504), $2,503 and $8,574 for Coal, Gas and All Other, respectively.

(F)    Includes investments in unconsolidated equity affiliates of $19,750, $135,048 and $58,910 for Coal, Gas and All Other, respectively.

27

Industry segment results for the nine months ended September 30, 2013 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	$	2,212,909	$	356,066	$	145,345	$	18,138		$	2,732,458	$	254,708	$	167,394	$	99,138		$	10,620		$	531,860		$	247,737		$	—		$	3,512,055	(G)
Sales—purchased gas	—		—		—		—			—		—		—		—			4,372			4,372			—			—			4,372
Sales—gas royalty interests	—		—		—		—			—		—		—		—			46,738			46,738			—			—			46,738
Freight—outside	—		—		—		35,749			35,749		—		—		—			—			—			—			—			35,749
Intersegment transfers	—		—		—		—			—		—		—		—			2,363			2,363			100,118			(102,481		)	—
Total Sales and Freight	$	2,212,909	$	356,066	$	145,345	$	53,887		$	2,768,207	$	254,708	$	167,394	$	99,138		$	64,093		$	585,333		$	347,855		$	(102,481	)	$	3,598,914
Earnings (Loss) Before Income Taxes	$	360,312	$	106,831	$	37,063	$	(259,421	)	$	244,785	$	64,345	$	53,389	$	(11,861	)	$	(112,990	)	$	(7,117	)	$	(48,426	)	$	(178,158	)	$	11,084	(H)
Segment assets										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(I)
Depreciation, depletion and amortization										$	307,992											$	163,079		$	18,703		$	—		$	489,774
Capital expenditures										$	511,626											$	669,067		$	15,216		$	—		$	1,195,909

(G)    Included in the Coal segment are sales of $492,872 to First Energy and $441,528 to Xcoal Energy & Resources each comprising over 10% of sales.

(H)     Includes equity in earnings of unconsolidated affiliates of $10,661, $9,519 and $96 for Coal, Gas and All Other, respectively.

(I)    Includes investments in unconsolidated equity affiliates of $20,131, $183,895 and $57,192 for Coal, Gas and All Other, respectively.

28

Industry segment results for the nine months ended September 30, 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	$	2,227,728	$	403,460	$	180,302	$	18,905		$	2,830,395	$	281,784	$	83,774	$	100,868		$	6,978		$	473,404	$	281,006	$	—		$	3,584,805	(J)
Sales—purchased gas	—		—		—		—			—		—		—		—			2,443			2,443		—		—			2,443
Sales—gas royalty interests	—		—		—		—			—		—		—		—			34,707			34,707		—		—			34,707
Freight—outside	—		—		—		126,195			126,195		—		—		—			—			—		—		—			126,195
Intersegment transfers	—		—		—		—			—		—		—		—			1,171			1,171		111,332		(112,503		)	—
Total Sales and Freight	$	2,227,728	$	403,460	$	180,302	$	145,100		$	2,956,590	$	281,784	$	83,774	$	100,868		$	45,299		$	511,725	$	392,338	$	(112,503	)	$	3,748,150
Earnings (Loss) Before Income Taxes	$	351,889	$	164,843	$	44,994	$	(134,271	)	$	427,455	$	91,717	$	14,433	$	(9,571	)	$	(71,271	)	$	25,308	$	27,539	$	(181,441	)	$	298,861	(K)
Segment assets										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594	(L)
Depreciation, depletion and amortization										$	297,148											$	148,344	$	—	$	17,556		$	463,048
Capital expenditures										$	702,880											$	408,278	$	40,863	$	—		$	1,152,021

(J) Included in the Coal segment are sales of $409,745 to First Energy and $382,950 to Xcoal Energy & Resources each comprising over 10% of sales.

(K) Includes equity in earnings of unconsolidated affiliates of $7,588, $6,484 and $8,604 for Coal, Gas and All Other, respectively.

(L)    Includes investments in unconsolidated equity affiliates of $19,750, $135,048 and $58,910 for Coal, Gas and All Other, respectively.

29

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
Segment Earnings Before Income Taxes for total reportable business segments	$	83,938		$	19,468		$	237,668		$	452,763
Segment (Loss) Earnings Before Income Taxes for all other businesses	(6,991		)	8,494			(48,426		)	27,539
Interest expense, net and other non-operating activity (M)	(57,482		)	(56,338		)	(166,548		)	(175,323		)
Other Corporate Items (M)	(8,891		)	(2,995		)	(11,610		)	(6,118		)
Earnings Before Income Taxes	$	10,574		$	(31,371	)	$	11,084		$	298,861

Total Assets:	September 30,
	2013		2012
Segment assets for total reportable business segments	$	11,787,041	$	11,465,377
Segment assets for all other businesses	356,848		376,400
Items excluded from segment assets:
Cash and other investments (M)	17,988		40,331
Recoverable income taxes	—		12,132
Deferred tax assets	538,930		618,742
Bond issuance costs	36,265		43,612
Total Consolidated Assets	$	12,737,072	$	12,556,594

_________________________ 

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

30

NOTE 15—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000, 8.000% per annum senior notes due April 1, 2017, the $1,250,000, 8.250% per annum senior notes due April 1, 2020, and the $250,000, 6.375% per annum senior 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 September 30, 2013 (unaudited):

	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	193,381		$	911,732		$	54,174		$	827		$	1,160,114
Sales—Gas Royalty Interests	—			15,506			—			—			—			15,506
Sales—Purchased Gas	—			1,608			—			—			—			1,608
Freight—Outside	—			—			11,563			—			—			11,563
Other Income	78,203			12,596			25,103			4,928			(78,203		)	42,627
Total Revenue and Other Income	78,203			223,091			948,398			59,102			(77,376		)	1,231,418
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	37,591			128,402			620,652			54,857			9,586			851,088
Gas Royalty Interests Costs	—			12,874			—			—			(10		)	12,864
Purchased Gas Costs	—			941			—			—			—			941
Related Party Activity	9,710			—			(29,271		)	458			19,103			—
Freight Expense	—			—			11,563			—			—			11,563
Selling, General and Administrative Expenses	—			11,600			21,582			290			—			33,472
Depreciation, Depletion and Amortization	3,288			58,444			106,910			510			—			169,152
Interest Expense	52,165			2,578			1,548			13			(3		)	56,301
Taxes Other Than Income	165			9,847			74,730			721			—			85,463
Total Costs	102,919			224,686			807,714			56,849			28,676			1,220,844
Earnings (Loss) Before Income Taxes	(24,716		)	(1,595		)	140,684			2,253			(106,052		)	10,574
Income Tax Expense (Benefit)	38,935			(602		)	37,143			(853		)	—			74,623
Net (Loss) Income	(63,651		)	(993		)	103,541			3,106			(106,052		)	(64,049		)
Add: Net Loss Attributable to Noncontrolling Interest	—			398			—			—			—			398
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(595	)	$	103,541		$	3,106		$	(106,052	)	$	(63,651	)

31

Balance Sheet at September 30, 2013 (unaudited):

	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	16,187	$	3,847		$	—		$	1,052	$	—		$	21,086
Accounts and Notes Receivable:
Trade	—		60,255			—			376,133		—			436,388
Notes Receivable	1,193		—			24,620			—		—			25,813
Other Receivables	3,866		144,253			7,780			5,032		—			160,931
Accounts Receivable—Securitized	—		—			—			44,364		—			44,364
Inventories	—		15,679			184,877			37,792		—			238,348
Deferred Income Taxes	106,291		(24,466		)	—			—		—			81,825
Restricted Cash	—		—			12,263			—		—			12,263
Prepaid Expenses	37,054		81,970			41,981			1,413		—			162,418
Total Current Assets	164,591		281,538			271,521			465,786		—			1,183,436
Property, Plant and Equipment:
Property, Plant and Equipment	218,303		6,586,647			9,740,510			25,644		—			16,571,104
Less-Accumulated Depreciation, Depletion and Amortization	139,157		1,122,401			4,659,763			18,926		—			5,940,247
Total Property, Plant and Equipment-Net	79,146		5,464,246			5,080,747			6,718		—			10,630,857
Other Assets:
Deferred Income Taxes	875,354		(418,249		)	—			—		—			457,105
Investment in Affiliates	10,234,178		183,895			750,771			—		(10,907,626		)	261,218
Notes Receivable	155		—			—			—		—			155
Other	109,998		39,916			44,822			9,565		—			204,301
Total Other Assets	11,219,685		(194,438		)	795,593			9,565		(10,907,626		)	922,779
Total Assets	$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	193,491	$	257,487		$	48,128		$	13,076	$	—		$	512,182
Accounts Payable (Recoverable)—Related Parties	3,882,644		39,594			(4,202,168		)	241,430		38,500			—
Current Portion Long-Term Debt	1,454		6,036			4,914			778		—			13,182
Short-Term Notes Payable	—		85,500			—			—		(38,500		)	47,000
Accrued Income Taxes	64,059		23,906			—			—		—			87,965
Borrowings Under Securitization Facility	—		—			—			44,364		—			44,364
Other Accrued Liabilities	209,321		70,835			578,019			10,729		—			868,904
Total Current Liabilities	4,350,969		483,358			(3,571,107		)	310,377		—			1,573,597
Long-Term Debt:	3,004,976		43,682			121,864			1,409		—			3,171,931
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			2,814,234			—		—			2,814,234
Pneumoconiosis Benefits	—		—			178,508			—		—			178,508
Mine Closing	—		—			460,515			—		—			460,515
Gas Well Closing	—		118,075			79,018			—		—			197,093
Workers’ Compensation	—		—			156,242			326		—			156,568
Salary Retirement	74,108		—			—			—		—			74,108
Reclamation	—		—			49,487			—		—			49,487
Other	75,204		12,227			16,424			—		—			103,855
Total Deferred Credits and Other Liabilities	149,312		130,302			3,754,428			326		—			4,034,368
Total CONSOL Energy Inc. Stockholders’ Equity	3,958,165		4,894,993			5,842,676			169,957		(10,907,626		)	3,958,165
Noncontrolling Interest	—		(989		)	—			—		—			(989		)
Total Liabilities and Equity	$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072

32

Income Statement for the Three Months Ended September 30, 2012 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	165,448	$	861,009		$	58,405	$	(821	)	$	1,084,041
Sales—Gas Royalty Interests	—			12,968		—			—		—			12,968
Sales—Purchased Gas	—			953		—			—		—			953
Freight—Outside	—			—		27,430			—		—			27,430
Other Income	(17,948		)	11,772		170,877			4,917		(134,921		)	34,697
Total Revenue and Other Income	(17,948		)	191,141		1,059,316			63,322		(135,742		)	1,160,089
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	18,699			96,619		647,158			57,408		7,646			827,530
Gas Royalty Interests Costs	—			10,565		—			—		(22		)	10,543
Purchased Gas Costs	—			737		—			—		—			737
Related Party Activity	8,575			—		(18,962		)	427		9,960			—
Freight Expense	—			—		27,430			—		—			27,430
Selling, General and Administrative Expenses	—			9,906		26,412			363		—			36,681
Depreciation, Depletion and Amortization	3,085			52,214		98,060			518		—			153,877
Interest Expense	50,811			1,145		2,267			11		(159		)	54,075
Taxes Other Than Income	(504		)	8,426		71,985			680		—			80,587
Total Costs	80,666			179,612		854,350			59,407		17,425			1,191,460
(Loss) Earnings Before Income Taxes	(98,614		)	11,529		204,966			3,915		(153,167		)	(31,371		)
Income Tax (Benefit) Expense	(87,246		)	4,433		61,424			1,491		—			(19,898		)
Net (Loss) Income	(11,368		)	7,096		143,542			2,424		(153,167		)	(11,473		)
Add: Net Loss Attributable to Noncontrolling Interest	—			105		—			—		—			105
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(11,368	)	$	7,201	$	143,542		$	2,424	$	(153,167	)	$	(11,368	)

33

Balance Sheet at December 31, 2012:

	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	17,491	$	3,352		$	175		$	860	$	—		$	21,878
Accounts and Notes Receivable:
Trade	—		58,126			—			370,202		—			428,328
Notes Receivable	154		315,730			2,503			—		—			318,387
Other Receivables	6,335		214,748			33,289			5,159		(128,400		)	131,131
Accounts Receivable—Securitized	—		—			—			37,846		—			37,846
Inventories	—		14,133			198,269			35,364		—			247,766
Deferred Income Taxes	174,176		(26,072		)	—			—		—			148,104
Restricted Cash	—		—			48,294			—		—			48,294
Prepaid Expenses	29,589		86,186			40,215			1,370		—			157,360
Total Current Assets	227,745		666,203			322,745			450,801		(128,400		)	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	216,448		5,956,207			9,347,370			25,179		—			15,545,204
Less-Accumulated Depreciation, Depletion and Amortization	126,048		960,613			4,249,507			18,069		—			5,354,237
Total Property, Plant and Equipment-Net	90,400		4,995,594			5,097,863			7,110		—			10,190,967
Other Assets:
Deferred Income Taxes	884,310		(439,725		)	—			—		—			444,585
Restricted Cash	—		—			20,379			—		—			20,379
Investment in Affiliates	9,917,050		143,876			769,058			—		(10,607,154		)	222,830
Notes Receivable	239		—			25,738			—		—			25,977
Other	118,938		65,935			32,016			10,188		—			227,077
Total Other Assets	10,920,537		(229,914		)	847,191			10,188		(10,607,154		)	940,848
Total Assets	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	177,734	$	166,182		$	154,936		$	9,130	$	—		$	507,982
Accounts Payable (Recoverable)-Related Parties	3,599,216		23,981			(3,749,584		)	254,787		(128,400		)	—
Current Portion of Long-Term Debt	1,554		5,953			5,222			756		—			13,485
Short-Term Notes Payable	25,073		—			—			—		—			25,073
Accrued Income Taxes	20,488		13,731			—			—		—			34,219
Borrowings Under Securitization Facility	—		—			—			37,846		—			37,846
Other Accrued Liabilities	135,407		57,074			566,485			9,528		—			768,494
Total Current Liabilities	3,959,472		266,921			(3,022,941		)	312,047		(128,400		)	1,387,099
Long-Term Debt:	3,005,515		46,081			121,523			1,467		—			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		—			2,832,401			—		—			2,832,401
Pneumoconiosis Benefits	—		—			174,781			—		—			174,781
Mine Closing	—		—			446,727			—		—			446,727
Gas Well Closing	—		80,097			68,831			—		—			148,928
Workers’ Compensation	—		—			155,342			306		—			155,648
Salary Retirement	218,004		—			—			—		—			218,004
Reclamation	—		—			47,965			—		—			47,965
Other	101,899		24,518			4,608			—		—			131,025
Total Deferred Credits and Other Liabilities	319,903		104,615			3,730,655			306		—			4,155,479
Total CONSOL Energy Inc. Stockholders’ Equity	3,953,792		5,014,313			5,438,562			154,279		(10,607,154		)	3,953,792
Noncontrolling Interest	—		(47		)	—			—		—			(47		)
Total Liabilities and Equity	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909

34

Income Statement for the Nine Months Ended September 30, 2013 (unaudited):

	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	534,221		$	2,813,430		$	161,837		$	2,567		$	3,512,055
Sales—Gas Royalty Interests	—			46,738			—			—			—			46,738
Sales—Purchased Gas	—			4,372			—			—			—			4,372
Freight—Outside	—			—			35,749			—			—			35,749
Other Income	354,386			37,055			86,064			15,705			(354,386		)	138,824
Total Revenue and Other Income	354,386			622,386			2,935,243			177,542			(351,819		)	3,737,738
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	117,830			359,397			1,971,483			162,050			29,169			2,639,929
Gas Royalty Interests Costs	—			38,235			—			—			(31		)	38,204
Purchased Gas Costs	—			2,961			—			—			—			2,961
Related Party Activity	32,385			—			(87,620		)	1,298			53,937			—
Freight Expense	—			—			35,749			—			—			35,749
Selling, General and Administrative Expenses	—			33,429			69,887			949			—			104,265
Depreciation, Depletion and Amortization	9,735			163,079			315,468			1,492			—			489,774
Interest Expense	153,141			6,375			4,871			34			(224		)	164,197
Taxes Other Than Income	430			25,534			223,254			2,357			—			251,575
Total Costs	313,521			629,010			2,533,092			168,180			82,851			3,726,654
Earnings (Loss) Before Income Taxes	40,865			(6,624		)	402,151			9,362			(434,670		)	11,084
Income Tax Expense (Benefit)	118,606			(2,557		)	(22,740		)	(3,542		)	—			89,767
Net (Loss) Income	(77,741		)	(4,067		)	424,891			12,904			(434,670		)	(78,683		)
Add: Net Loss Attributable to Noncontrolling Interest	—			942			—			—			—			942
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(77,741	)	$	(3,125	)	$	424,891		$	12,904		$	(434,670	)	$	(77,741	)

35

Income Statement for the Nine Months Ended September 30, 2012 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	474,574	$	2,919,814	$	192,212	$	(1,795	)	$	3,584,805
Sales—Gas Royalty Interests	—			34,707		—		—		—			34,707
Sales—Purchased Gas	—			2,443		—		—		—			2,443
Freight—Outside	—			—		126,195		—		—			126,195
Other Income	399,817			46,177		230,930		16,089		(399,817		)	293,196
Total Revenue and Other Income	399,817			557,901		3,276,939		208,301		(401,612		)	4,041,346
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	90,230			296,959		1,992,371		186,635		22,265			2,588,460
Gas Royalty Interests Costs	—			27,951		—		—		(35		)	27,916
Purchased Gas Costs	—			2,123		—		—		—			2,123
Related Party Activity	1,575			—		5,078		1,376		(8,029		)	—
Freight Expense	—			—		126,195		—		—			126,195
Selling, General and Administrative Expenses	—			29,199		79,169		1,044		—			109,412
Depreciation, Depletion and Amortization	8,901			148,343		304,245		1,559		—			463,048
Interest Expense	158,505			3,554		7,056		33		(360		)	168,788
Taxes Other Than Income	159			24,790		229,381		2,213		—			256,543
Total Costs	259,370			532,919		2,743,495		192,860		13,841			3,742,485
Earnings (Loss) Before Income Taxes	140,447			24,982		533,444		15,441		(415,453		)	298,861
Income Tax (Benefit) Expense	(98,120		)	9,706		143,001		5,841		—			60,428
Net Income (Loss)	238,567			15,276		390,443		9,600		(415,453		)	238,433
Add: Net Loss Attributable to Noncontrolling Interest	—			134		—		—		—			134
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	238,567		$	15,410	$	390,443	$	9,600	$	(415,453	)	$	238,567

36

Cash Flow for the Nine Months EndedSeptember 30, 2013 (unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(7,813	)	$	383,504		$	180,580		$	(5,766	)	$	38,500		$	589,005
Cash Flows from Investing Activities:
Capital Expenditures	$	(15,216	)	$	(669,067	)	$	(511,626	)	$	—		$	—		$	(1,195,909	)
Change in Restricted Cash	—			—			56,410			—			—			56,410
Proceeds from Sales of Assets	—			335,142			263,015			17			—			598,174
Net Investments In Equity Affiliates	—			(30,500		)	12,388			—			—			(18,112		)
Net Cash (Used in) Provided by Investing Activities	$	(15,216	)	$	(364,425	)	$	(179,813	)	$	17		$	—		$	(559,437	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	85,500		$	—		$	—		$	(38,500	)	$	47,000
Payments on Miscellaneous Borrowings	(26,591		)	—			(5,122		)	(577		)	—			(32,290		)
Proceeds from Securitization Facility	—			—			—			6,518			—			6,518
Dividends Received (Paid)	42,789			(100,000		)	—			—			—			(57,211		)
Proceeds from Issuance of Common Stock	2,698			—			—			—			—			2,698
Other Financing Activities	2,925			(4,084		)	4,084			—			—			2,925
Net Cash Provided by (Used in) Financing Activities	$	21,821		$	(18,584	)	$	(1,038	)	$	5,941		$	(38,500	)	$	(30,360	)

Cash Flow for the Nine Months EndedSeptember 30, 2012 (unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(245,017	)	$	139,026		$	635,257		$	897		$	—	$	530,163
Cash Flows from Investing Activities:
Capital Expenditures	$	(40,863	)	$	(408,278	)	$	(702,880	)	$	—		$	—	$	(1,152,021	)
Net Investments In Equity Affiliates	—			(31,650		)	12,949			—			—		(18,701		)
Proceeds from Sales of Assets	169,500			359,636			54,756			50			—		583,942
Net Cash Provided by (Used in) Investing Activities	$	128,637		$	(80,292	)	$	(635,175	)	$	50		$	—	$	(586,780	)
Cash Flows from Financing Activities:
Dividends Received (Paid)	$	114,710		$	(200,000	)	$	—		$	—		$	—	$	(85,290	)
Other Financing Activities	3,304			(4,107		)	(1,729		)	(339		)	—		(2,871		)
Net Cash (Used in) Provided by Financing Activities	$	118,014		$	(204,107	)	$	(1,729	)	$	(339	)	$	—	$	(88,161	)

37

Statement of Comprehensive Income for the Three Months Ended September 30, 2013 (Unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(63,651	)	$	(993	)	$	103,541	$	3,106	$	(106,052	)	$	(64,049	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	24,980			—			24,980		—		(24,980		)	24,980
Net Increase (Decrease) in the Value of Cash Flow Hedge	13,246			13,246			—		—		(13,246		)	13,246
Reclassification of Cash Flow Hedge from OCI to Earnings	(24,354		)	(24,354		)	—		—		24,354			(24,354		)
Other Comprehensive Income (Loss):	13,872			(11,108		)	24,980		—		(13,872		)	13,872
Comprehensive (Loss) Income	(49,779		)	(12,101		)	128,521		3,106		(119,924		)	(50,177		)
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			398			—		—		—			398
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(49,779	)	$	(11,703	)	$	128,521	$	3,106	$	(119,924	)	$	(49,779	)

Statement of Comprehensive Income for the Three Months Ended September 30, 2012 (Unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(11,368	)	$	7,096		$	143,542	$	2,424	$	(153,167	)	$	(11,473	)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	7,921			—			7,921		—		(7,921		)	7,921
Net (Decrease) Increase in the Value of Cash Flow Hedge	(6,459		)	(6,459		)	—		—		6,459			(6,459		)
Reclassification of Cash Flow Hedge from OCI to Earnings	(47,809		)	(47,809		)	—		—		47,809			(47,809		)
Other Comprehensive (Loss) Income:	(46,347		)	(54,268		)	7,921		—		46,347			(46,347		)
Comprehensive (Loss) Income	(57,715		)	(47,172		)	151,463		2,424		(106,820		)	(57,820		)
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			105			—		—		—			105
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(57,715	)	$	(47,067	)	$	151,463	$	2,424	$	(106,820	)	$	(57,715	)

38

Statement of Comprehensive Income for the Nine Months EndedSeptember 30, 2013 (Unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(77,741	)	$	(4,067	)	$	424,891	$	12,904	$	(434,670	)	$	(78,683	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	113,641			—			113,641		—		(113,641		)	113,641
Net Increase (Decrease) in the Value of Cash Flow Hedge	40,400			40,400			—		—		(40,400		)	40,400
Reclassification of Cash Flow Hedge from OCI to Earnings	(56,595		)	(56,595		)	—		—		56,595			(56,595		)
Other Comprehensive Income (Loss):	97,446			(16,195		)	113,641		—		(97,446		)	97,446
Comprehensive Income (Loss)	19,705			(20,262		)	538,532		12,904		(532,116		)	18,763
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			942			—		—		—			942
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	19,705		$	(19,320	)	$	538,532	$	12,904	$	(532,116	)	$	19,705

Statement of Comprehensive Income for the Nine Months EndedSeptember 30, 2012 (Unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	238,567		$	15,276		$	390,443	$	9,600	$	(415,453	)	$	238,433
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	75,080			—			75,080		—		(75,080		)	75,080
Net Increase (Decrease) in the Value of Cash Flow Hedge	80,280			80,280			—		—		(80,280		)	80,280
Reclassification of Cash Flow Hedge from OCI to Earnings	(153,597		)	(153,597		)	—		—		153,597			(153,597		)
Other Comprehensive Income (Loss):	1,763			(73,317		)	75,080		—		(1,763		)	1,763
Comprehensive Income (Loss)	240,330			(58,041		)	465,523		9,600		(417,216		)	240,196
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			134			—		—		—			134
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	240,330		$	(57,907	)	$	465,523	$	9,600	$	(417,216	)	$	240,330

39

NOTE 16—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the the three and nine months ended September 30, 2013, 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 $9,498 and $22,954 for the three and nine months ended September 30, 2013, respectively, and were $5,895 and $13,619 for the three and nine months ended September 30, 2012, respectively, which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of September 30, 2013 and December 31, 2012, CONSOL Energy and CNX Gas Company had a net payable of $1,563 and $3,142, respectively, due CONE which was comprised of the following items:

	September 30,			December 31,
	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(1,380	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(181		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	3,124			4,837			Accounts Payable
Net Payable due CONE	$	1,563		$	3,142

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: (a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

NOTE 18—SUBSEQUENT EVENT:

On October 25, 2013, CONSOL Energy entered into an agreement to sell Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy).  The CCC mines being sold are McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 28.5 million tons of thermal coal in 2012. Murray Energy is acquiring approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations are included in the transaction. In 2012, the fleet of 21 towboats and 600 barges transported 19.3 million tons of coal and other commodities along the upper Ohio River system. CONSOL Energy will receive $850,000 in cash as a result of the transaction and in addition Murray Energy will assume certain employee and environmental related liabilities with a book value of approximately $2,400,000 at September 30, 2013. The final financial gain will be calculated upon closing, which is expected to occur during the fourth quarter.

40

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

General

Natural gas prices trended downward in the third quarter after rising above $4.00 per MMBtu in the first half of the year. When measured by cooling degree days, the summer was both cooler than last year and the trailing four year average for the same period, by 9% and 7% respectively. As a result, electric generation fell by about 2% compared with the same quarter last year which exerted downward pressure on demand for generation fuels. From a fuel-mix perspective, coal-fired electric generation increased by 4% year over year, while higher natural gas prices reduced gas consumption by 10% over the same period. Gas production saw a modest growth of around 2% in the third quarter. With this decrease in power demand and increase in supply, natural gas underground inventory levels increased but were in line with the five year average.

Third quarter coal consumption was aided by higher natural gas prices when compared with last year. As natural gas prices stayed well above last year’s low, coal-fired electric generation remained strong in a lower demand market. Early government data showed that coal-fired electric generation gained market share, accounting for 41% of total electric generation compared with 39% for the same quarter last year. This increase primarily displaced natural gas-fired generation which accounted for 30% of total generation, compared with 33% for the same quarter last year. Conventional hydropower, which accounts for 7% of overall U.S. electric generation, was down 10% compared with its performance last year. Current coal inventory levels stayed below the five year average. Compared with the prior year for the same period, increased natural gas prices and reduced domestic coal production contributed to the stabilization of coal prices.

In the longer term, the outlook for domestic thermal coal continues to face regulatory challenges.  In line with the current administration’s climate change initiative and the upcoming 2015 deadline for the U.S. Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) rule, utilities are retiring non-compliant as well as less efficient coal-fired units. Additionally, the EPA has been directed to draft regulations for new as well as existing fossil-fuel electric generation plants in order to limit greenhouse gases by June 2014 and finalize the same by June 2015.

Internationally, U.S. coal exports are expected to decline in 2013 after a record year in 2012.  After a strong first half, early government data for the second half of the year shows a 12% decline in thermal exports, thus causing the full year 2013 exports to be nearly 9% lower than full year 2012.  Low international pricing, in combination with a stronger domestic market, contributed to the decline.  Longer-term fundamentals for U.S. thermal coal exports remain favorable as subsidized mining in Europe is phased out, nuclear growth plans are curtailed, and coal continues to maintain a cost advantage over other more expensive oil-linked fuels. U.S. natural gas net imports declined by 19% for the quarter compared with same period last year. This reduction is primarily driven by the increase of domestic supply from certain shale plays such as the Marcellus.Recent government approval of a fourth LNG export facility increases distribution channels for U.S. produced natural gas while showing greater long-term government support of U.S. natural gas production.

The U.S. third quarter benchmark price for premium metallurgical coal settled lower than the prior quarter. Toward the end of the quarter, prices began to slightly improve off of three-year lows. The overall current price environment is indicative of what has been an oversupplied global metallurgical coal market. However, recent price increases may indicate market fundamentals are beginning to stabilize.

Global steel production in 2013 has grown at a 4% annualized rate over 2012, largely driven by record production in China. Steel production outside of China has remained under pressure as a result of limited demand growth and steel mill overcapacity. As a result of a challenged seaborne market, annualized U.S. metallurgical coal exports in 2013 are down 3% from 2012.

CONSOL Energy has entered into an agreement to sell Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy).  The CCC mines being sold are McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 28.5 million tons of thermal coal in 2012. Murray Energy is acquiring approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations are included in the transaction. In 2012, the fleet of 21 towboats and 600 barges transported 19.3 million tons of coal and other commodities along the upper Ohio River system. CONSOL Energy will receive $850 million in cash as a result of the transaction.  Additionally, Murray Energy will assume approximately $2.1 billion of other postretirement benefit plan liabilities, $105 million of workers compensation liabilities, $61 million of coal workers’ pneumoconiosis liabilities, $13 million of long term disability liabilities, $149 million of environmental liabilities and CONSOL Energy’s UMWA 1974

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Pension Trust Obligations. The final financial gain will be calculated upon closing, which is expected to occur during the fourth quarter.  Also in conjunction with the sale, CONSOL Energy is realigning its dividend policy to reflect the company’s increased emphasis on growth. Beginning with the first declared quarterly dividend after the transaction closes, CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, for an annual rate of $0.25 per share.

CONSOL Energy has entered into a farm-in agreement for approximately 80,000 additional Marcellus Shale acres in West Virginia and title due diligence is ongoing through closing.  Consideration of up to $190 million will be paid by CONSOL Energy in two installments:  (i) 50% due at closing and (ii) the balance due over time as the acres are drilled.  Closing is anticipated to occur in early December 2013. In accordance with the negotiated terms of our Marcellus Joint Venture, CONSOL will offer a 50% interest in all rights under the farm-in agreement to Noble Energy.

CONSOL Energy's coal sales outlook is as follows:

	Q4 2013		2013		2014		2015
Estimated Coal Sales (millions of tons)	13.6 - 14.0		57.0 - 57.4		30.1		33.8
Est. Low-Vol Met Sales	0.7 - 0.9		4.3 - 4.5		4.2		4.9
Tonnage: Firm	0.7		4.2		0.9		0.8
Avg. Price: Sold (Firm)	$	92.27	$	95.34	$	100.62	$	102.50
Est. High-Vol Met Sales	0.5+		2.8+		1.8		1.4
Tonnage: Firm	0.5		2.8		0.2		0.2
Avg. Price: Sold (Firm)	$	61.31	$	63.27	$	79.80	$	75.33
Est. Thermal Sales	12.4+		49.9+		24.1		27.5
Tonnage: Firm	12.4		49.9		18.9		10.1
Avg. Price: Sold (Firm)	$	58.19	$	58.94	$	64.05	$	67.00

Note: While the data in the table are single point estimates, the inherent uncertainty of markets and mining operations means that investors should consider a reasonable range around these estimates. CONSOL has chosen not to forecast prices for open tonnage due to ongoing customer negotiations. In the thermal sales category, the open tonnage includes two items: sold, but unpriced tons and collared tons. There are no collared tons in 2014. Collared tons in 2015 are 1.4 million tons, with a ceiling of $72.59 per ton and a floor of $48.59 per ton. Calendar year 2013 includes 0.1 million tons of mid-vol coal from Amonate. The Amonate tons are not included in the category breakdowns. Also, not included in the category breakdowns are the tons from equity affiliates Harrison Resources and Western Allegheny Energy (WAE). Harrison Resources has 0.4 million tons for 2013, 2014, and 2015. WAE has 0.3, 0.5, and 0.9 million tons for 2013, 2014, and 2015, respectively. Coal Division guidance for 2014 - 2015 excludes the five mines that will be sold in CONSOL Energy's recent transaction. However, fourth quarter 2013 guidance includes these mines.

CONSOL Energy expects total coal production will be between 56.7 – 57.1 million tons for the year. Fourth quarter coal production is expected to be between 13.6 – 14.0 million tons.

Fourth quarter gas production, net to CONSOL, is expected to be approximately 46 – 48 Bcfe. If achieved, this would result in 2013 annual production of approximately 170 – 172 Bcfe. CONSOL Energy expects its 2014 annual gas production to be between 210 – 225 Bcfe with annual production growth, thereafter, between 25% - 30% through 2016.

Several significant events occurred in the nine months ended September 30, 2013. These events include the following:

• In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24.7 million. The transaction resulted in a $15.3 million gain on the sale of assets.

• On June 24, 2013, CONSOL Energy closed the sale of the Potomac coal reserves located in Grant and Tucker Counties in West Virginia. Cash proceeds from the sale were $25.0 million. The transaction resulted in a $24.7 million gain on the sale of assets.

• Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company's salary retirement pension plan exceeding the annual projected service and interest costs of the plan. The pension settlement resulted in a $38.5 million pre-tax expense adjustment. Many of the lump sum payments in the nine months ended September 30, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive Plan. Also, pension settlement required the pension plan to be remeasured using updated assumptions at September 30, 2013. The updated assumptions include resetting the discount rate used in the actuarial calculation. See Note 3 - Components of Pension and Other Post-Employment Benefit (OPEB) Plans Net

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Periodic Benefit Costs, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details of the updated assumptions.

• A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the nine months ended September 30, 2013. As a result of the Company's review of the title defect notice, asserted by Noble, and working in collaboration with Noble, CONSOL Energy has addressed defects of $21.8 million. See Note 8 - Property, Plant and Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

• CNX Gas Company completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play.  CNX Gas Company paid $46.3 million as an up-front bonus payment at closing. Approximately 7.6% percent of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title.  CNX Gas Company must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas forgoes the bonus. Our joint venture partner, Noble Energy, has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs in June 2013.

• On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County, Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified and containment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. This event resulted in a pre-tax expense of $38.6 million in the nine months ended September 30, 2013.

• In the nine months ended September 30, 2013, an agreement in principle was reached for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010 in principle. The total settlement provides for a payment to the plaintiffs of $42.73 million, of which the company expects to pay $19.2 million. On May 8, 2013, the parties executed and filed with the Court a stipulation and agreement of compromise and settlement. A settlement hearing was held by the Court on August 23, 2013, and the settlement was approved. See Note 11 - Commitments and Contingencies, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

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

• The Cross States Air Pollution Rule (CSAPR) was finalized by the Environmental Protection Agency (EPA) in July 2011. The rule required reductions in SO2 and NOx emissions in the eastern U.S. by January 1, 2012 (phase 1) and January 1, 2014 (phase 2). However, CSAPR was vacated by a three-judge panel of the D.C. Circuit on August 21, 2012, and the full D.C. Circuit declined to hear the case in January 2013. EPA and environmental groups appealed the decision to the Supreme Court on March 29, 2013. Until legal challenges are resolved and/or EPA develops a replacement rule, the Clean Air Interstate Rule (CAIR) will remain in effect.

• On July 9, 2013, Pennsylvania Governor, Tom Corbett signed the Oil and Gas Lease Act (SB 529). The Act reinstated the Guaranteed Minimum Royalty Act of 1979 and it permits pooling of already leased acreage. The Act does not authorize forced pooling.

• Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include increased scrutiny of existing safety regulations and the development of new safety regulations and additional environmental restrictions.

• 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.

• 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.  OSM has indicated that it will not issue a draft rule or a draft environmental impact statement until sometime in 2014.  Other examples are the Mercury and Air Toxic Standards (MATS) (remanded by the court and re-proposed by the EPA in November 2012) and the Utility Maximum Achievable Control Technology (Utility MACTS) rules issued by the EPA. These 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.  The EPA reconsidered the UMACT rules and recently finalized revised new source performance

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standards for coal based power plants which raised some emission limits.  The standards remain stringent and costly for compliance. On April 18, 2012, the EPA published new final New Source Performance Standards for gas wells and related facilities. These rules 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.

• In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide emissions from coal powered electric generating units. The proposed rules would have applied to new power plants and to existing plants that make major modifications. If the rules had been adopted as proposed, the only new coal fired power plants that could have met the proposed emission limits would have been coal fired plants with carbon dioxide capture and storage (CCS). Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal fired electric generation units uneconomical compared to new gas fired electric generation units.  On September 20, 2013, EPA re-proposed NSPS for CO₂ for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012. These proposed rules will also require CCS for new coal fired power plants.

• CONSOL Energy surface coal mining operations in West Virginia are subject to several citizen suits and several citizen groups' Notices of Intent to Sue relating to alleged violations of water discharge permits from our coal mining operations.  In each of these matters, CONSOL Energy investigates the complaints, if necessary develops and implements compliance plans, and defends the citizen suits as appropriate. 

• In late June 2012, CONSOL Energy received informal notification from the Pennsylvania Department of Environmental Protection of the Department's intent pursuant to a Technical Guidance Document entitled “Surface Water Protection-Underground Bituminous Coal Mining” to require a change in the mine plan of a pending application for a permit for expansion of the Company's Bailey longwall mine.  If ultimately required, this change in mine plan could have a material effect on CONSOL Energy's forecasted production for 2015. CONSOL Energy does not agree that a modification of its mining plan is necessary to comply with applicable regulatory performance standards and continues to submit information to the permitting authority to support its position. Additionally, CONSOL Energy is currently evaluating potential modifications that would be required if CONSOL Energy is compelled to modify its application.

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Results of Operations

Three Months EndedSeptember 30, 2013 Compared with Three Months EndedSeptember 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $64 million, or $(0.28) per diluted share, for the three months ended September 30, 2013. Net loss attributable to CONSOL Energy shareholders was $11 million, or $(0.05) per diluted share, for the three months ended September 30, 2012.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $86 million of earnings before income tax for the three months ended September 30, 2013 compared to $8 million for the three months ended September 30, 2012. The total coal division sold 14.4 million tons of coal produced from CONSOL Energy mines for the three months ended September 30, 2013 compared to 12.3 million tons for the three months ended September 30, 2012.

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

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	61.26	$	67.31	$	(6.05	)	(9.0	)%
Average Cost of Goods Sold per ton	50.46		55.84		(5.38		)	(9.6	)%
Margin per ton sold	$	10.80	$	11.47	$	(0.67	)	(5.8	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical and thermal coal markets. The average coal sales price in the 2013 period was also lower due to the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013.

Changes in the average cost of goods sold per ton were primarily related to the following items:

• Average cost of goods sold decreased due to additional tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

• On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

• Direct services to operations are improved due to a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.

• Average direct operating costs were impaired due to CONSOL Energy entering into several new longwall leases in 2013 at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.

The total gas division includes CBM, Shallow Oil and Gas, Marcellus and other gas. The total gas division had a $2 million loss before income tax for the three months ended September 30, 2013 compared to $12 million of income before income tax for the three months ended September 30, 2012. Total gas production was 46.1 billion cubic feet for the three months ended September 30, 2013 compared to 39.5 billion cubic feet for the three months ended September 30, 2012. Total gas volumes increased primarily as a result of the on-going Marcellus drilling program.

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

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	4.20	$	4.19	$	0.01		0.2%
Average Costs per thousand cubic feet sold	3.23		3.38		(0.15		)	(4.4)%
Margin per thousand cubic feet sold	$	0.97	$	0.81	$	0.16		19.8%

Total gas division outside sales revenues were $193 million for the three months ended September 30, 2013 compared to $165 million for the three months ended September 30, 2012. The increase was primarily due to the 16.7% increase in volumes sold, along with a 0.2% increase in average price per thousand cubic feet sold. The increase in average sales price is the result

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of the increase in general market prices and sales of natural gas liquids and condensate, partially offset by various gas swap transactions that occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 24.0 billion cubic feet of our produced gas sales volumes for the three months ended September 30, 2013 at an average price of $4.63 per thousand cubic feet. These financial hedges represented 19.3 billion cubic feet of our produced gas sales volumes for the three months ended September 30, 2012 at an average price of $5.25 per thousand cubic feet.

Changes in the average cost per thousand cubic feet of gas sold were primarily related to the following items:

• Higher volumes in the period-to-period comparison, due to the on-going Marcellus drilling program, resulted in an overall improvement in unit costs. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

• Lifting costs were improved on a unit basis due to the increase in volumes, offset by higher accretion expense related to the estimated well plugging liability and increased road repair and maintenance costs.

• Depreciation, depletion and amortization was also improved due to the increase in volumes. This improvement was offset by higher units-of-production rates for producing properties.

• The improvement in gathering costs on a unit basis, due to the increase in volumes, was offset by higher firm transportation costs and increased processing fees associated with natural gas liquids.

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.

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. General and Administrative costs are excluded from the coal and gas unit costs above. Total General and Administrative costs were made up of the following items:

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Contributions	$	2	$	4	$	(2	)	(50.0	)%
Employee Wages and Related Expenses	13		14		(1		)	(7.1	)%
Advertising and Promotion	2		2		—			—	%
Consulting and Professional Services	7		6		1			16.7	%
Miscellaneous	6		7		(1		)	(14.3	)%
Total Company General and Administrative Expenses	$	30	$	33	$	(3	)	(9.1	)%

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

• Contributions decreased $2 million related to various transactions that occurred throughout both periods, none of which are individually significant.

• Employee wages and related expenses decreased $1 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit expenses (OPEB) in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.

• Advertising and promotion remained consistent in the period-to-period comparison.

• Consulting and professional services increased $1 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which are individually significant.

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

Total Company long-term liabilities, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial liabilities was $64 million for the three months ended September 30, 2013 and September 30, 2012. Total CONSOL Energy expense remained consistent in the period-to-period comparison even though pension settlement accounting was required resulting in $6 million of expense. Pension settlement expenses were required when the lump sum distributions made for the 2013 plan year exceeded the total of the service and interest costs for the 2013 plan year. The pension settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for coal or gas. This was offset due to a modification to the benefit plan for salaried employees and an increase in the discount rate assumptions used to calculate expense for benefit

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plans at the measurement date, which is December 31. See Note 3 - Components of Pension and Other Post-Employment 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 September 30, 2013 compared to the three months ended September 30, 2012:

The coal segment contributed $86 million of earnings before income tax in the three months ended September 30, 2013 compared to $8 million in the three months ended September 30, 2012. Variances by the individual coal segments are discussed below.

	For the Three Months Ended														Difference to Three Months Ended
	September 30, 2013														September 30, 2012
	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	$	752		$	30	$	98		$	—		$	880		$	85		$	(18	)	$	(12	)	$	—		$	55
Purchased Coal	1			—		—			7			8			1			—			—			2			3
Total Outside Sales	753			30		98			7			888			86			(18		)	(12		)	2			58
Freight Revenue	—			—		—			12			12			—			—			—			(15		)	(15		)
Other Income	—			—		—			25			25			(1		)	(1		)	—			7			5
Total Revenue and Other Income	753			30		98			44			925			85			(19		)	(12		)	(6		)	48
Costs and Expenses:
Beginning inventory costs	43			—		9			—			52			(66		)	(2		)	(17		)	—			(85		)
Total direct operating costs	393			15		45			41			494			68			(7		)	—			(29		)	32
Total royalty/production taxes	51			1		6			1			59			6			(1		)	(1		)	1			5
Total direct services to operations	65			3		7			46			121			6			(2		)	1			(19		)	(14		)
Total retirement and disability	44			2		6			3			55			4			(1		)	(1		)	(6		)	(4		)
Depreciation, depletion and amortization	79			3		11			11			104			12			(2		)	2			(4		)	8
Ending inventory costs	(51		)	—		(7		)	—			(58		)	16			—			26			1			43
Total Costs and Expenses	624			24		77			102			827			46			(15		)	10			(56		)	(15		)
Freight Expense	—			—		—			12			12			—			—			—			(15		)	(15		)
Total Costs	624			24		77			114			839			46			(15		)	10			(71		)	(30		)
Earnings (Loss) Before Income Taxes	$	129		$	6	$	21		$	(70	)	$	86		$	39		$	(4	)	$	(22	)	$	65		$	78

THERMAL COAL SEGMENT

The thermal coal segment contributed $129 million to total Company earnings before income tax for the three months ended September 30, 2013 and $90 million for the three months ended September 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:

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	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	12.8		10.8		2.0			18.5	%
Average Sales Price Per Thermal Ton Sold	$	59.08	$	62.11	$	(3.03	)	(4.9	)%
Beginning Inventory Costs Per Thermal Ton	$	55.36	$	56.03	$	(0.67	)	(1.2	)%
Total Direct Operating Costs Per Thermal Ton Produced	$	30.38	$	32.24	$	(1.86	)	(5.8	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	3.91		4.46		(0.55		)	(12.3	)%
Total Direct Services to Operations Per Thermal Ton Produced	5.06		5.87		(0.81		)	(13.8	)%
Total Retirement and Disability Per Thermal Ton Produced	3.43		4.04		(0.61		)	(15.1	)%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	6.14		6.70		(0.56		)	(8.4	)%
Total Production Costs Per Thermal Ton Produced	$	48.92	$	53.31	$	(4.39	)	(8.2	)%
Ending Inventory Costs Per Thermal Ton	$	52.26	$	51.55	$	0.71		1.4	%
Total Costs Per Thermal Ton Sold	$	49.07	$	53.81	$	(4.74	)	(8.8	)%
Average Margin Per Thermal Ton Sold	$	10.01	$	8.30	$	1.71		20.6	%

Thermal coal revenue was $753 million for the three months ended September 30, 2013 compared to $667 million for the three months ended September 30, 2012. The $86 million increase was attributable to a 2.0 million increase in tons sold offset, in part, by a $3.03 per ton lower average sales price. The lower average thermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013. The increase in sales tons was primarily due to the July 27, 2012 structural failure of the above-ground conveyor system at the Bailey Preparation Plant which resulted in fewer tons in the 2012 period. The decrease in price was partially offset by 0.9 million tons of thermal coal being priced on the export market at an average sales price of $63.74 per ton for the three months ended September 30, 2013 compared to 0.8 million tons at an average price of $61.93 per ton for the three months ended September 30, 2012.

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.

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for thermal coal was $624 million for the three months ended September 30, 2013, or $46 million higher than the $578 million for the three months ended September 30, 2012. Total cost of goods sold for thermal coal was $49.07 per ton in the three months ended September 30, 2013 compared to $53.81 per ton in the three months ended September 30, 2012. The increase in total dollars and decrease in unit costs per thermal ton was primarily due to the increase in tons sold. The items described below also had an impact on cost of goods sold.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the thermal coal segment were $393 million in the three months ended September 30, 2013 compared to $325 million in the three months ended September 30, 2012. Direct operating costs were $30.38 per ton produced in the current period compared to $32.24 per ton produced in the prior period. Changes in the average direct operating costs per thermal ton produced were primarily related to the following items:

• Average cost of goods sold decreased due to additional tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

• As previously discussed, on July 27, 2012 a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

• In response to weak market conditions for domestic coal, the annual miner's vacation period at Blacksville No. 2 and Robinson Run mines was extended for a period of two weeks in July 2012. These mines operated in the 2013 period which resulted in higher costs.

48

• In 2013, CONSOL Energy entered into several new longwall leases which resulted in a higher cost per ton produced in the period-to-period comparison.

Royalties and production taxes were $51 million, or impaired $6 million in the current period compared to $45 million in the prior period. Unit costs improved $0.55 per thermal ton produced to $3.91 in the current period. The $6 million increase was primarily due to higher production tons, although higher production tons resulted in lower unit costs.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The cost of these support services was $65 million in the current period compared to $59 million in the prior period. Direct services to the operations were $5.06 per ton produced in the current period compared to $5.87 per ton produced in the prior period. Changes in the average direct service to operations cost per thermal ton produced were primarily related to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as previously discussed. Unit costs were also improved due to the increase in production tons.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the thermal coal segment were $44 million for the three months ended September 30, 2013 compared to $40 million for the three months ended September 30, 2012. The increase in thermal coal retirement and disability costs was primarily attributable to the reduction in active employee counts at the Bailey Mine in the 2012 period, due to the structural failure as previously discussed. The increase was offset, in part, by a decrease in total thermal coal retirement and disability costs primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after September 30, 2012. These impairments were offset, in part, by the increase in production tons which had a positive impact on unit costs.

Depreciation, depletion and amortization for the thermal coal segment was $79 million for the three months ended September 30, 2013 compared to $67 million for the three months ended September 30, 2012. The $12 million increase was due to higher depletion directly related to higher tons produced. Unit cost were improved due to higher volumes produced, which allows for cost of straight-line depreciation to be spread over additional volumes.

Changes in thermal coal inventory volumes and carrying value resulted in an $8 million decrease in cost of goods sold in the three months ended September 30, 2013 and a $42 million increase in cost of goods sold in the three months ended September 30, 2012. Thermal coal inventory was 1.0 million tons at September 30, 2013 compared to 1.3 million tons at September 30, 2012.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $6 million to total Company earnings before income tax for the three months ended September 30, 2013 compared to $10 million for the three months ended September 30, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:

49

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.5		0.7		(0.2		)	(28.6	)%
Average Sales Price Per High Vol Met Ton Sold	$	60.42	$	67.76	$	(7.34	)	(10.8	)%
Beginning Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%
Total Direct Operating Costs Per High Vol Met Ton Produced	$	29.85	$	30.10	$	(0.25	)	(0.8	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	3.06		3.09		(0.03		)	(1.0	)%
Total Direct Services to Operations Per High Vol Met Ton Produced	5.21		7.26		(2.05		)	(28.2	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.09		3.89		(0.80		)	(20.6	)%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	6.05		7.38		(1.33		)	(18.0	)%
Total Production Costs Per High Vol Met Ton Produced	$	47.26	$	51.72	$	(4.46	)	(8.6	)%
Ending Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%
Total Costs Per High Vol Met Ton Sold	$	47.25	$	55.29	$	(8.04	)	(14.5	)%
Margin Per High Vol Met Ton Sold	$	13.17	$	12.47	$	0.70		5.6	%

High volatile metallurgical coal revenue was $30 million for the three months ended September 30, 2013 compared to $48 million for the three months ended September 30, 2012. Average sales prices for high volatile metallurgical coal decreased $7.34 per ton in the period-to-period comparison. CONSOL Energy priced 0.5 million tons of high volatile metallurgical coal in the export market at an average sales price of $60.42 per ton for the three months ended September 30, 2013 compared to 0.6 million tons at an average price of $65.96 per ton for the three months ended September 30, 2012. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

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

Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $24 million for the three months ended September 30, 2013, or $15 million lower than the $39 million for the three months ended September 30, 2012. Total cost of goods sold for high volatile metallurgical coal was $47.25 per ton in the three months ended September 30, 2013 compared to $55.29 per ton in the three months ended September 30, 2012. The decrease in total dollars and unit costs per high volatile metallurgical ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the high volatile metallurgical coal segment were $15 million in the three months ended September 30, 2013 compared to $22 million in the three months ended September 30, 2012. Direct operating costs were $29.85 per ton produced in the current period compared to $30.10 per ton produced in the prior period. Changes in the average direct operating costs per ton for high volatile metallurgical coal sold were primarily related to the mix of mines which sold on the high volatile coal market in the period-to-period comparison. Mines with higher cost structures produced a larger portion of the high volatile metallurgical coal shipped in the prior period compared to the current period. This resulted in lower direct operating costs in the period-to-period comparison. The impact of the improvements on unit costs, was offset, in part, by lower tons produced which negatively impacted unit costs.

Royalties and production taxes were $1 million or improved $1 million in the current period primarily related to the mix of mines which sold on the high volatile metallurgical coal market. Mines with higher royalty rates produced a larger portion of the high volatile metallurgical coal shipped in the prior period compared to the current period.

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Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for high volatile metallurgical coal were $3 million in the current period compared to $5 million in the prior period. Decreased costs were attributable to lower subsidence costs due to the timing and nature of properties undermined. Direct services to the operations for high volatile metallurgical coal were $5.21 per ton produced in the current period compared to $7.26 per ton produced in the prior period. Changes in the average direct service to operations cost per ton for high volatile metallurgical coal produced were primarily related to lower subsidence expenses offset, in part, by lower tons produced.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the high volatile metallurgical coal segment were $2 million for the three months ended September 30, 2013 compared to $3 million in the three months ended September 30, 2012. The decrease in total high volatile metallurgical coal retirement and disability total dollars and unit costs was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after September 30, 2012. Unit costs were negatively impacted due to the reduction in tons produced.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $3 million for the three months ended September 30, 2013 compared to $5 million in the three months ended September 30, 2012. The decrease was primarily due to lower depletion directly related to lower production tons.

There were no changes in volumes or carrying value of coal inventory in the three months ended September 30, 2013 and September 30, 2012. There was no high volatile metallurgical coal inventory at September 30, 2013 or September 30, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $21 million to total Company earnings before income tax in the three months ended September 30, 2013 compared to $43 million in the three months ended September 30, 2012. 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 September 30,
	2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	1.1		0.8		0.3			37.5	%
Average Sales Price Per Low Vol Met Ton Sold	$	85.77	$	135.66	$	(49.89	)	(36.8	)%
Beginning Inventory Costs Per Low Vol Met Ton	$	64.76	$	69.84	$	(5.08	)	(7.3	)%
Total Direct Operating Costs Per Low Vol Met Ton Produced	$	41.07	$	55.61	$	(14.54	)	(26.1	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.16		8.75		(3.59		)	(41.0	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.98		6.83		(0.85		)	(12.4	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.57		8.63		(3.06		)	(35.5	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	9.55		11.29		(1.74		)	(15.4	)%
Total Production Costs Per Low Vol Met Ton Produced	$	67.33	$	91.11	$	(23.78	)	(26.1	)%
Ending Inventory Costs Per Low Vol Met Ton	$	65.42	$	87.32	$	(21.90	)	(25.1	)%
Total Costs Per Low Vol Met Ton Sold	$	67.18	$	83.09	$	(15.91	)	(19.1	)%
Margin Per Low Vol Met Ton Sold	$	18.59	$	52.57	$	(33.98	)	(64.6	)%

Low volatile metallurgical coal revenue was $98 million for the three months ended September 30, 2013 compared to $110 million for the three months ended September 30, 2012. The $12 million decrease was attributable to a $49.89 per ton lower average sales price and was partially offset by a 0.3 million increase in tons sold. Average sales prices for low volatile

51

metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. For the 2013 period, 0.9 million tons of low volatile metallurgical coal were priced on the export market at an average price of $79.06 per ton compared to 0.6 million tons at an average price of $114.26 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal was $77 million for the three months ended September 30, 2013, or $10 million higher than the $67 million for the three months ended September 30, 2012. Total cost of goods sold for low volatile metallurgical coal was $67.18 per ton in the three months ended September 30, 2013 compared to $83.09 per ton in the three months ended September 30, 2012. The increase in total dollars and decrease in unit costs per low volatile metallurgical ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the low volatile metallurgical coal segment were $45 million in the three months ended September 30, 2013 and September 30, 2012. Direct operating costs were $41.07 per ton produced in the current period compared to $55.61 per ton produced in the prior period. The $14.54 improvement in unit costs is directly related to the increase in production tons. Production tons are higher in the current period due to the Buchanan Mine being idled in September 2012 in response to the weak world economy.

Royalties and production taxes were $6 million, or improved $1 million in the current period, compared to $7 million in the prior period. Unit costs were also improved $3.59 per low volatile metallurgical ton produced to $5.16 per ton produced in the current period compared to $8.75 per ton produced in the prior period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes. These decreases were primarily related to the $49.89 decrease in average sales price, which is the basis for most royalties and production taxes.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for low volatile metallurgical coal were $7 million in the current period and $6 million in the prior period. Direct services to the operations for low volatile metallurgical coal were $5.98 per ton produced in the current period compared to $6.83 per ton produced in the prior period. Changes in the average direct service to operations cost per ton for low volatile metallurgical coal produced were primarily related to an increase in water treatment cost. The impact of higher expenses on unit costs was offset by additional production tons.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the low volatile metallurgical coal segment were $6 million for the three months ended September 30, 2013 compared to $7 million for the three months ended September 30, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred on September 30, 2012. This, coupled with the increase in production tons, resulted in an improvement on the unit costs of $3.06 in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $11 million for the three months ended September 30, 2013 compared to $9 million for the three months ended September 30, 2012. Total dollars and unit costs per low volatile metallurgical tons produced were higher in the three months ended September 30, 2013 compared to the three months ended September 30, 2012 primarily due to the Buchanan Mine being idled in September 2012. Overall, unit costs were improved $1.74 per low volatile metallurgical ton produced due to the increase in production tons.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of $2 million to cost of goods sold in the three months ended September 30, 2013 and a decrease of $7 million to cost of goods sold in the three months ended September 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at September 30, 2013 compared to 0.4 million tons at September 30, 2012.

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OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $70 million for the three months ended September 30, 2013 compared to a loss before income tax of $135 million for the three months ended September 30, 2012. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the three months ended September 30, 2012. No coal was recovered during the reclamation process at idled facilities for the three months ended September 30, 2013. 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 and coal purchased from third parties and sold directly to our customers. The revenues were $7 million for the three months ended September 30, 2013 compared to $5 million for the three months ended September 30, 2012.

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 by freight expense. Freight revenue was $12 million for the three months ended September 30, 2013 compared to $27 million for the three months ended September 30, 2012. The $15 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $25 million for the three months ended September 30, 2013 compared to $18 million for the three months ended September 30, 2012. The change is due to the following items:

• Gain on sale of assets attributable to the Other Coal segment was $18 million in the three months ended September 30, 2013 compared to $1 million in the three months ended September 30, 2012. The increase of $17 million was primarily related to the 2013 sale of 1.5 MM tons of Pittsburgh 8 Coal that CONSOL Energy controlled in Belmont County, OH for a gain of $2 million and the 2013 sale of 50% interest in a joint venture in Alberta, Canada for a gain of $15 million. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of these sales.

• Equity in earnings of affiliates decreased $3 million due to lower earnings from our equity affiliates.

• For the three months ended September 30, 2012 there was $5 million of income from certain thermal coal contract buyouts. There were no corresponding transactions in three months ended September 30, 2013.

• The remaining $2 million decrease is due to various items, none of which are individually significant.

Other coal segment total costs were $114 million for the three months ended September 30, 2013 compared to $185 million for the three months ended September 30, 2012. The decrease of $71 million was primarily due to the following items:

	For the Three Months Ended September 30,
	2013		2012		Variance
Bailey Belt Incident	$	—	$	42	$	(42	)
Freight Expense	12		27		(15		)
Closed and Idle Mines	33		40		(7		)
General and Administrative Expense	17		20		(3		)
Stock-based Compensation	7		4		3
Purchased Coal	12		10		2
Other	33		42		(9		)
Total Other Coal Segment Costs	$	114	$	185	$	(71	)

• Bailey Belt Incident costs represent expenses during the belt-reconstruction period related to continued advancement of the mines and on-going projects at the mines

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• Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

• Closed and idle mine costs decreased approximately $7 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Closed and idle mine costs decreased $8 million due to the decision to shutdown the Fola Mining Complex in August 2012 and $7 million due to the decision to idle operations at Buchanan Mine in September 2012. These decreases were offset, in part, by an increase of $8 million in costs incurred primarily by the Amonate complex.

• General and Administrative Expense related to the other coal segment decreased by $3 million primarily due to various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section "Net Income" of this quarterly report for detailed cost explanations.

• Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense for employees who received awards under the new CONSOL Share Unit (CSU) program.  The new program replaces several previously provided long-term executive compensation award programs.  The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.

• Purchased coal costs increased $2 million due to higher amounts of coal that needed to be purchased to fulfill various contracts.

• Other expenses related to the Other Coal segment decreased $9 million due to various transactions that occurred throughout both periods, none of which were individually material.

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TOTAL GAS SEGMENT ANALYSIS for the three months ended September 30, 2013 compared to the three months ended September 30, 2012:

The gas segment had a $2 million loss before income tax in the three months ended September 30, 2013 compared to earnings before income tax of $12 million in the three months ended September 30, 2012.

	For the Three Months Ended													Difference to Three Months Ended
	September 30, 2013													September 30, 2012
	CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	83	$	33		$	72	$	4		$	192		$	(11	)	$	1		$	36	$	2		$	28
Related Party	1		—			—		—			1			—			—			—		—			—
Total Outside Sales	84		33			72		4			193			(11		)	1			36		2			28
Gas Royalty Interest	—		—			—		15			15			—			—			—		2			2
Purchased Gas	—		—			—		2			2			—			—			—		1			1
Other Income	—		—			—		13			13			—			—			—		1			1
Total Revenue and Other Income	84		33			72		34			223			(11		)	1			36		6			32
Lifting	8		9			5		2			24			(1		)	(1		)	2		2			2
Ad Valorem, Severance, and Other Taxes	3		2			3		—			8			1			—			2		(2		)	1
Gathering	28		7			11		1			47			1			1			4		—			6
Gas Direct Administrative, Selling & Other	2		2			6		2			12			(1		)	(1		)	—		3			1
Depreciation, Depletion and Amortization	22		15			19		2			58			(1		)	1			6		—			6
General & Administration	—		—			—		12			12			—			—			—		2			2
Gas Royalty Interest	—		—			—		13			13			—			—			—		2			2
Purchased Gas	—		—			—		1			1			—			—			—		—			—
Exploration and Other Costs	—		—			—		23			23			—			—			—		16			16
Other Corporate Expenses	—		—			—		25			25			—			—			—		9			9
Interest Expense	—		—			—		2			2			—			—			—		1			1
Total Cost	63		35			44		83			225			(1		)	—			14		33			46
Earnings Before Income Tax	$	21	$	(2	)	$	28	$	(49	)	$	(2	)	$	(10	)	$	1		$	22	$	(27	)	$	(14	)

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COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $21 million to the total Company earnings before income tax for the three months ended September 30, 2013 compared to $31 million for the three months ended September 30, 2012.

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	21.0		21.7		(0.7		)	(3.2	)%
Average CBM sales price per thousand cubic feet sold	$	3.99	$	4.36	$	(0.37	)	(8.5	)%
Average CBM lifting costs per thousand cubic feet sold	0.39		0.41		(0.02		)	(4.9	)%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.12		0.11		0.01			9.1	%
Average CBM gathering costs per thousand cubic feet sold	1.31		1.26		0.05			4.0	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.11		0.11		—			—	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.06		1.04		0.02			1.9	%
Total Average CBM costs per thousand cubic feet sold	2.99		2.93		0.06			2.0	%
Average Margin for CBM	$	1.00	$	1.43	$	(0.43	)	(30.1	)%

CBM sales revenues were $84 million in the three months ended September 30, 2013 and $95 million for the three months ended September 30, 2012. Sales volumes decreased 3.2% and the average sales price decreased 8.5% per thousand cubic feet sold. The decrease in CBM average sales price was the result of an increase in market prices offset by various gas swap transactions that matured 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 13.8 billion cubic feet of our produced CBM gas sales volumes for the three months ended September 30, 2013 at an average price of $4.49 per thousand cubic feet. For the three months ended September 30, 2012, these financial hedges represented 11.4 billion cubic feet at an average price of $5.34 per thousand cubic feet. CBM sales volumes decreased 0.7 billion cubic feet for the three months ended September 30, 2013 compared to the 2012 period primarily due to normal well declines and fewer CBM wells being drilled. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage.

Total costs for the CBM segment were $63 million for the three months ended September 30, 2013 compared to $64 million for the three months ended September 30, 2012. The decrease in total dollars and increase in unit costs for the CBM segment are due to the following items:

•CBM lifting costs were $8 million for the three months ended September 30, 2013 compared to $9 million for the three months ended September 30, 2012. The decrease in total dollars and unit costs was primarily due to lower road maintenance and lower contractor services in the period-to-period comparison. The impact of lower expenses on unit costs was offset, in part, by lower volumes sold.

•CBM ad valorem, severance and other taxes were $3 million for the three months ended September 30, 2013 compared to $2 million for the three months ended September 30, 2012. The increase in total dollars and unit costs was primarily due to an increase in severance tax expense caused by an increase in the average gas sales price, without the impact of hedging, as described above.

•CBM gathering costs were $28 million for the three months ended September 30, 2013 compared to $27 million for the three months ended September 30, 2012. The $1 million increase and $0.05 increase in average per unit costs were due to increased transportation costs, increased pipeline maintenance, and increased road maintenance. Unit costs were also negatively impacted by the reduction in sales volumes.

•CBM direct administrative, selling & other costs were $2 million for the three months ended September 30, 2013 compared to $3 million for the three months ended September 30, 2012. 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 decrease in direct administrative, selling & other costs was primarily due to reduced direct administrative labor and CBM volumes representing a smaller proportion of total natural gas volumes sold.

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•Depreciation, depletion and amortization attributable to the CBM segment was $22 million for the three months ended September 30, 2013 compared to $23 million for the three months ended September 30, 2012. There was approximately $15 million, or $0.73 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2013. The production portion of depreciation, depletion and amortization was $15 million, or $0.68 per unit-of-production in the three months ended September 30, 2012. There was approximately $7 million, or $0.33 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended September 30, 2013. The non-production related depreciation, depletion and amortization was $8 million, or $0.35 per thousand cubic feet for the three months ended September 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $2 million for the three months ended September 30, 2013 compared to a loss before income tax of $3 million for the three months ended September 30, 2012.

	For the Three Months Ended September 30,
	2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	6.8			7.0			(0.2		)	(2.9	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	4.85		$	4.59		$	0.26		5.7	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.36			1.44			(0.08		)	(5.6	)%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.27			0.37			(0.10		)	(27.0	)%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.01			0.87			0.14			16.1	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.37			0.35			0.02			5.7	%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.15			2.05			0.10			4.9	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.16			5.08			0.08			1.6	%
Average Margin for Shallow Oil and Gas	$	(0.31	)	$	(0.49	)	$	0.18		36.7	%

Shallow Oil and Gas sales revenues were $33 million for the three months ended September 30, 2013 compared to $32 million for the three months ended September 30, 2012. The 2.9% decrease in volumes sold was offset, in part, by a 5.7% increase in average sales price. The decrease in volumes was due to normal well declines without a corresponding increase in wells drilled. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage. The increase in shallow oil and gas average sales price is the result of higher average market prices offset by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 3.8 billion cubic feet of our produced shallow oil and gas sales volumes for the three months ended September 30, 2013 at an average price of $5.16 per thousand cubic feet. For the three months ended September 30, 2012, these financial hedges represented 4.9 billion cubic feet at an average price of $5.23 per thousand cubic feet.

Total costs for the shallow oil and gas segment were $35 million for the three months ended September 30, 2013 and 2012. The $0.08 increase in costs per thousand cubic feet sold for the shallow oil and gas segment is due to the following items:

•Shallow Oil and Gas lifting costs were $9 million for the three months ended September 30, 2013 compared to $10 million for the three months ended September 30, 2012. The $1 million decrease in total costs is due to lower road maintenance, lower salt water disposal costs and lower contract services in the current period offset, in part, by an increase in accretion expense on the well plugging liability. The impact of the decrease on unit costs was offset by lower sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes were $2 million for the three months ended September 30, 2013 and 2012.

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•Shallow Oil and Gas gathering costs were $7 million for the three months ended September 30, 2013 compared to $6 million for the three months ended September 30, 2012. Gathering costs increased $1 million primarily due to an increase in firm transportation costs in the period-to-period comparison. The increase was offset, in part, by a decrease in repair and maintenance costs.

•Shallow Oil and Gas direct administrative, selling & other costs were $2 million for the three months ended September 30, 2013 compared to $3 million for the three months ended September 30, 2012. 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 reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes sold. The decrease in costs was offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization costs were $15 million for the three months ended September 30, 2013 compared to $14 million for the three months ended September 30, 2012. There was approximately $13 million, or $1.89 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 September 30, 2013. There was approximately $12 million, or $1.79 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 September 30, 2012. There was approximately $2 million, or $0.26 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 September 30, 2013 and 2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $28 million to the total Company earnings before income tax for the three months ended September 30, 2013 compared to $6 million for the three months ended September 30, 2012.

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	17.4		10.1		7.3			72.3	%
Average Marcellus sales price per thousand cubic feet sold	$	4.16	$	3.58	$	0.58		16.2	%
Average Marcellus lifting costs per thousand cubic feet sold	0.29		0.32		(0.03		)	(9.4	)%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.17		0.12		0.05			41.7	%
Average Marcellus gathering costs per thousand cubic feet sold	0.66		0.68		(0.02		)	(2.9	)%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.34		0.55		(0.21		)	(38.2	)%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.09		1.28		(0.19		)	(14.8	)%
Total Average Marcellus costs per thousand cubic feet sold	2.55		2.95		(0.40		)	(13.6	)%
Average Margin for Marcellus	$	1.61	$	0.63	$	0.98		155.6	%

The Marcellus segment sales revenues were $72 million for the three months ended September 30, 2013 compared to $36 million for the three months ended September 30, 2012. The $36 million increase is primarily due to a 72.3% increase in volumes sold, and a 16.2% increase in average sales price in the period-to-period comparison. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program. The increase in Marcellus average sales price was the result of higher market prices and an increase in the sale of natural gas liquids and condensate, offset by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 6.4 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended September 30, 2013 at an average price of $4.62 per thousand cubic feet. For the three months ended September 30, 2012, these financial hedges represented 3.0 billion cubic feet at an average price of $4.97 per thousand cubic feet.

Total costs for the Marcellus segment were $44 million for the three months ended September 30, 2013 compared to $30 million for the three months ended September 30, 2012. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

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•Marcellus lifting costs were $5 million for the three months ended September 30, 2013 compared to $3 million for the three months ended September 30, 2012. The $2 million increase primarily relates to increased road maintenance costs and increased well tending costs. Lifting costs per unit decreased due to higher volumes sold.

•Marcellus ad valorem, severance and other taxes were $3 million for the three months ended September 30, 2013 and $1 million for the three months ended September 30, 2012. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by higher average gas sales prices and the 72.3% increase in volumes sold during the current period.

•Marcellus gathering costs were $11 million for the three months ended September 30, 2013 compared to $7 million for the three months ended September 30, 2012. Total dollars and unit costs increased due to increased firm transportation costs and increased processing fees associated with natural gas liquids. Overall, unit costs were improved due to the increase in volumes sold.

•Marcellus direct administrative, selling & other costs were $6 million for the three months ended September 30, 2013 and 2012. 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 $0.21 decrease in costs per thousand cubic feet sold is attributable to the 72.3% increase in volumes sold.

•Depreciation, depletion and amortization costs were $19 million for the three months ended September 30, 2013 compared to $13 million for the three months ended September 30, 2012. There was approximately $19 million, or $1.08 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2013. There was approximately $12 million, or $1.22 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 September 30, 2012. There was less than $1 million, or $0.01 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended September 30, 2013. There was $1 million, or $0.06 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended September 30, 2012.

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 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 and the Utica Shale in Ohio. Revenue from these operations were approximately $4 million for the three months ended September 30, 2013 and $2 million for the three months ended September 30, 2012. Total costs related to these other sales were $7 million for the three months ended September 30, 2013 compared to $4 million for the three months ended September 30, 2012. A per unit analysis of the other operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas sales revenue was $15 million for the three months ended September 30, 2013 compared to $13 million for the three months ended September 30, 2012. 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 increase.

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.5		4.8		(1.3		)	(27.1	)%
Average Sales Price Per thousand cubic feet	$	4.41	$	2.67	$	1.74		65.2	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $2 million for the three months ended September 30, 2013 and $1 million for the three months ended September 30, 2012.

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	For the Three Months Ended September 30,
	2013		2012		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	$	5.14	$	3.29	$	1.85	56.2	%

Other income was $13 million for the three months ended September 30, 2013 compared to $12 million for the three months ended September 30, 2012. The $1 million change was primarily due to the following items:

• There was an increase of $3 million related to increased earnings from our equity affiliates.

• Gains on dispositions of non-core acreage and equipment increased $2 million due to various transactions that occurred throughout both periods, none of which are individually material.

• Interest income decreased $4 million due to the collection of the final installment on the notes receivable from the Noble joint venture transaction.

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 $12 million for the three months ended September 30, 2013 compared to $10 million for the three months ended September 30, 2012. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders"of this quarterly report for a detailed cost explanation.

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 $13 million for the three months ended September 30, 2013 compared to $11 million for the three months ended September 30, 2012. 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 September 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.5		4.8		(1.3		)	(27.1	)%
Average Cost Per thousand cubic feet sold	$	3.66	$	2.18	$	1.48		67.9	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million for the three months ended September 30, 2013 and 2012.

	For the Three Months Ended September 30,
	2013		2012		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	$	3.01	$	3.04	$	(0.03	)	(1.0	)%

Exploration and other costs were $23 million for the three months ended September 30, 2013 compared to $7 million for the three months ended September 30, 2012. The $16 million increase is due to the following items:

	For the Three Months Ended September 30,
	2013		2012		Variance		Percent Change
Marcellus Title Defects	$	13	$	2	$	11	550.0	%
Lease Expiration Costs	3		1		2		200.0	%
Exploration	7		4		3		75.0	%
Total Exploration and Other Costs	$	23	$	7	$	16	228.6	%

• CONSOL Energy has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a book value to CONSOL Energy of $13 million for the three months ended September 30, 2013 compared to $2 million for the three months ended September 30, 2012.

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• Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $2 million increase is due to a greater number of leases which CONSOL Energy choose to let expire in the current period when compared with the prior period.

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

Other corporate expenses were $25 million for the three months ended September 30, 2013 compared to $16 million for the three months ended September 30, 2012. The $9 million increase in the period-to-period comparison was made up of the following items:

	For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change
Unutilized firm transportation	$	12	$	4	$	8		200.0	%
Short term incentive compensation	7		5		2			40.0	%
Stock-based compensation	4		4		—			—	%
Bank fees	2		2		—			—	%
Legal fees	—		1		(1		)	(100.0	)%
Total Other Corporate Expenses	$	25	$	16	$	9		56.3	%

• Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The $8 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

• The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense was higher for the 2013 period compared to the 2012 period due to higher projected payouts.

• Stock-based compensation remained consistent in the period-to-period comparison.

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

• Legal fees decreased $1 million due to various transactions, none of which were individually material.

Interest expense related to the gas segment was $2 million for the three months ended September 30, 2013 compared to $1 million for the three months ended September 30, 2012. Interest was incurred on the CNX Gas revolving credit facility and a capital lease. The $1 million increase was primarily due to higher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the three months endedSeptember 30, 2013compared to the three months endedSeptember 30, 2012:

The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $72 million for the three months ended September 30, 2013 compared to a loss before income tax of $53 million for the three months ended September 30, 2012. The other segment also includes total Company income tax expense of $75 million for the three months ended September 30, 2013 compared to an income tax benefit of $20 million for the three months ended September 30, 2012.

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	For the Three Months Ended September 30,
	2013			2012			Variance			Percent Change
Sales—Outside	$	79		$	88		$	(9	)	(10.2	)%
Other Income	5			3			2			66.7	%
Total Revenue	84			91			(7		)	(7.7	)%
Cost of Goods Sold and Other Charges	94			82			12			14.6	%
Depreciation, Depletion & Amortization	6			6			—			—	%
Taxes Other Than Income Tax	2			3			(1		)	(33.3	)%
Interest Expense	54			53			1			1.9	%
Total Costs	156			144			12			8.3	%
Loss Before Income Tax	(72		)	(53		)	(19		)	35.8	%
Income Tax	75			(20		)	95			475.0	%
Net Loss	$	(147	)	$	(33	)	$	(114	)	(345.5	)%

Industrial supplies:

Outside Sales from industrial supplies were $54 million for the three months ended September 30, 2013 compared to $58 million for the three months ended September 30, 2012. The decrease of $4 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $53 million for the three months ended September 30, 2013 compared to $56 million for the three months ended September 30, 2012. The decrease of $3 million was primarily related to lower sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Outside Sales from transportation operations were $25 million for the three months ended September 30, 2013 compared to $30 million for the three months ended September 30, 2012. The decrease of $5 million was primarily attributable to decreased thru-put as well as lower per ton thru-put rates for the quarter.

Total costs related to the transportation operations were $24 million for the three months ended September 30, 2013 compared to $22 million for the three months ended September 30, 2012. Costs increased $2 million due to higher per ton thru-put costs offset, in part, by decreased thru-put volumes.

Miscellaneous other:

Additional other income of $5 million was recognized for the three months ended September 30, 2013 compared to $3 million for the three months ended September 30, 2012. The $2 million increase is due to various items in both periods, none of which were individually material.

Other corporate costs were $79 million for the three months ended September 30, 2013 compared to $66 million for the three months ended September 30, 2012. Other corporate costs increased due to the following items:

	For the Three Months Ended September 30,
	2013		2012		Variance
Corporate Initiative Fees and Other Legal Charges	$	10	$	3	$	7
Pension Settlement	6		—		6
Bank Fees	4		3		1
Interest Expense	52		53		(1		)
Other	7		7		—
	$	79	$	66	$	13

• Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. See Note 8 - Property, Plant and

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Equipment and Note 11 - Commitments and Contingencies of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.

• Pension settlement expenses were required when the lump sum distributions made for the 2013 plan year exceeded the total of the service and interest costs for the 2013 plan year.

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

• Interest expense decreased $1 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.

• Other corporate items remained consistent in the period-to-period comparsion.

Income Taxes:

The effective income tax rate was 705.7% for the three months ended September 30, 2013 compared to 63.4% for the three months ended September 30, 2012. The effective rates for the three months ended September 30, 2013 and 2012 were calculated using the annual effective rate projection on recurring earnings and include tax liabilities related to certain discrete transactions. The $75 million of tax expense for the quarter reflects the Company’s expectation of minimal pre-tax income, excluding gains on sales of assets, for 2013 without a corresponding decrease in excess percentage depletion benefits generated by the Coal division. When pre-tax earnings, excluding gain on sales of assets, approaches breakeven without corresponding reductions in excess percentage depletion, effective tax rates calculated under accounting guidance for interim periods produce results that are not necessarily indicative of the expected tax expense/benefits of the annual period. 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 September 30,
	2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	11		$	(31	)	$	42		(133.9	)%
Income Tax Expense	$	75		$	(20	)	$	95		(477.4	)%
Effective Income Tax Rate	705.7		%	63.4		%	642.3		%

Results of Operations

Nine Months EndedSeptember 30, 2013 Compared with Nine Months EndedSeptember 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $78 million, or $(0.34) per diluted share, for the nine months ended September 30, 2013. Net income attributable to CONSOL Energy shareholders was $239 million, or $1.04 per diluted share, for the nine months ended September 30, 2012.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $245 million of earnings before income tax for the nine months ended September 30, 2013 compared to $427 million for the nine months ended September 30, 2012. The total coal division sold 43.4 million tons of coal produced from CONSOL Energy mines for the nine months ended September 30, 2013 and 41.7 million tons of coal produced from CONSOL Energy mines for the nine months ended September 30, 2012.

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

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	62.54	$	67.35	$	(4.81	)	(7.1	)%
Average Cost of Goods Sold per ton	50.99		54.09		(3.10		)	(5.7	)%
Margin per ton sold	$	11.55	$	13.26	$	(1.71	)	(12.9	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical and thermal coal markets. The coal division priced 7.3 million tons on the export market at an average sales price of $71.52 for the nine months ended September 30, 2013 compared to 8.8 million tons at an average price of $76.24 per ton for the nine months ended September 30, 2012. All other tons were sold on the domestic market.

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Changes in the average cost of goods sold per ton were primarily related to the following items:

• Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

• On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

• Direct operating costs improved primarily due to a decrease in all direct operating costs at the Blacksville No. 2 Mine which was the result of the mine being idled March 12, 2013 until May 20, 2013 due to a fire. Also, in March and April 2012, the Blacksville No. 2 Mine ran the continuous miners and worked on various projects, while the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.

• The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.

• Direct services to operations are improved primarily due to a reduction in subsidence expenses related to the timing and nature of properties and streams undermined as well as a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.

• Depreciation, depletion and amortization was improved primarily due to lower production at Blacksville No. 2 Mine related to the mine being shut down in 2013 due to the fire, and due to the shutdown of operations at the Fola Mining Complex in August 2012. The improvements were offset, in part, by higher costs in the 2013 period due to the reduction in production at both the Bailey and Enlow Fork Mines in the 2012 period as a result of the structural failure and due to the idling of the Buchanan Mine in September 2012 in response to the weak world economy.

• Average direct operating costs were impaired due to CONSOL Energy entering into several new longwall leases in 2013 at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.

• Costs were impaired in the current period due to the idling of the Buchanan Mine in September 2012. Also, in March and April 2012, the Buchanan Mine ran the continuous miners and worked on various projects, but the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.

The total gas division includes CBM, Shallow Oil and Gas, Marcellus and other gas. The total gas division had a $7 million loss before income tax for the nine months ended September 30, 2013 compared to $25 million of earnings before income tax for the nine months ended September 30, 2012. Total gas production was 123.9 billion cubic feet for the nine months ended September 30, 2013 compared to 114.5 billion cubic feet for the nine months ended September 30, 2012. Total gas volumes increased primarily as a result of the on-going Marcellus drilling program.

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

	For the Nine Months Ended September 30,
	2013		2012		Variance		Percent Change
Average Sales Price per thousand cubic feet sold	$	4.31	$	4.14	$	0.17	4.1%
Average Costs per thousand cubic feet sold	3.49		3.36		0.13		3.9%
Margin per thousand cubic feet sold	$	0.82	$	0.78	$	0.04	5.1%

Total gas division outside sales revenues were $534 million for the nine months ended September 30, 2013 compared to $475 million for the nine months ended September 30, 2012. The increase was primarily due to the 8.2% increase in volumes sold, along with a 4.1% increase in average price per thousand cubic feet sold. The increase in average sales price is the result of the increase in general market prices and sales of natural gas liquids, partially offset by various gas swap transactions that occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 60.3 billion cubic feet of our produced gas sales volumes for the nine months ended September 30, 2013 at an average price of $4.71 per thousand cubic feet. These financial hedges represented 57.5 billion cubic feet of our produced gas sales volumes for the nine months ended September 30, 2012 at an average price of $5.25 per thousand cubic feet.

Changes in the average cost per thousand cubic feet of gas sold were primarily related to the following items:

• Gathering costs increased in the period-to-period comparison due to higher firm transportation costs and increased processing fees associated with natural gas liquids.

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• Lifting costs increased due to increased accretion expense on the well plugging liability as well as increased salt water disposal costs. These impairments were partially offset by improvements related to decreased expenditures for contract services, environmental compliance and safety costs and well services costs in the current period.

• Depreciation, depletion and amortization rates increased due to higher units-of-production for producing properties.

• These increases were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling program. Fixed costs are allocated over increased volumes, resulting in lower unit 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.

General and administrative costs are allocated between divisions (Coal, Gas and Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and administrative costs are excluded from the coal and gas unit costs above. Total general and administrative costs were made up of the following items:

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Employee Wages and Related Expenses	$	40	$	46	$	(6	)	(13.0	)%
Contributions	8		9		(1		)	(11.1	)%
Advertising and Promotion	6		6		—			—	%
Consulting and Professional Services	23		17		6			35.3	%
Miscellaneous	20		21		(1		)	(4.8	)%
Total Company General and Administrative Expenses	$	97	$	99	$	(2	)	(2.0	)%

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

• Employee wages and related expenses decreased $6 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.

• Contributions decreased $1 million related to various transactions that occurred throughout both periods, none of which were individually material.

• Advertising and promotion remained consistent in the period-to-period comparison.

• Consulting and professional services increased $6 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which were individually significant.

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

Total Company long-term liabilities, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy expense related to our actuarial liabilities was $219 million for the nine months ended September 30, 2013 compared to $195 million for the nine months ended September 30, 2012. The increase of $24 million for total CONSOL Energy expense was primarily due to required pension settlement accounting which resulted in $39 million of expense. Pension settlement expenses were required when lump sum distributions made for the 2013 plan year exceeded the total of the service cost and interest cost for the 2013 plan year. The pension settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for coal or gas. This was offset, in part, due to a modification to the benefit plan for salaried employees and an increase in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31. See Note 3 - Components of Pension and Other Post-Employment 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 increase.

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TOTAL COAL SEGMENT ANALYSIS for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012:

The coal segment contributed $245 million of earnings before income tax in the nine months ended September 30, 2013 compared to $427 million in the nine months ended September 30, 2012. Variances by the individual coal segments are discussed below.

	For the Nine Months Ended														Difference to Nine Months Ended
	September 30, 2013														September 30, 2012
	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	$	2,212		$	145	$	356		$	—		$	2,713		$	(16	)	$	(35	)	$	(47	)	$	(6	)	$	(104	)
Purchased Coal	—			—		—			18			18			—			—			—			5			5
Total Outside Sales	2,212			145		356			18			2,731			(16		)	(35		)	(47		)	(1		)	(99		)
Freight Revenue	—			—		—			36			36			—			—			—			(90		)	(90		)
Other Income	2			2		—			85			89			1			(5		)	—			(144		)	(148		)
Total Revenue and Other Income	2,214			147		356			139			2,856			(15		)	(40		)	(47		)	(235		)	(337		)
Costs and Expenses:
Beginning inventory costs	58			—		21			—			79			(31		)	(2		)	5			—			(28		)
Total direct operating costs	1,154			72		147			140			1,513			19			(12		)	(13		)	6			—
Total royalty/production taxes	153			4		20			1			178			1			(5		)	(5		)	(1		)	(10		)
Total direct services to operations	183			13		18			170			384			(27		)	(6		)	1			(40		)	(72		)
Total retirement and disability	133			7		20			11			171			—			(2		)	(3		)	(4		)	(9		)
Depreciation, depletion and amortization	224			14		30			40			308			(1		)	(5		)	—			17			11
Ending inventory costs	(51		)	—		(7		)	—			(58		)	16			—			26			1			43
Total Costs and Expenses	1,854			110		249			362			2,575			(23		)	(32		)	11			(21		)	(65		)
Freight Expense	—			—		—			36			36			—			—			—			(90		)	(90		)
Total Costs	1,854			110		249			398			2,611			(23		)	(32		)	11			(111		)	(155		)
Earnings (Loss) Before Income Taxes	$	360		$	37	$	107		$	(259	)	$	245		$	8		$	(8	)	$	(58	)	$	(124	)	$	(182	)

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THERMAL COAL SEGMENT

The thermal coal segment contributed $360 million to total Company earnings before income tax for the nine months ended September 30, 2013 and $352 million for the nine months ended September 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	37.4		36.0		1.4			3.9	%
Average Sales Price Per Thermal Ton Sold	$	59.16	$	61.79	$	(2.63	)	(4.3	)%
Beginning Inventory Costs Per Thermal Ton	$	50.92	$	58.32	$	(7.40	)	(12.7	)%
Total Direct Operating Costs Per Thermal Ton Produced	$	30.98	$	31.68	$	(0.70	)	(2.2	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	4.11		4.25		(0.14		)	(3.3	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.90		5.89		(0.99		)	(16.8	)%
Total Retirement and Disability Per Thermal Ton Produced	3.56		3.71		(0.15		)	(4.0	)%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	6.02		6.28		(0.26		)	(4.1	)%
Total Production Costs Per Thermal Ton Produced	$	49.57	$	51.81	$	(2.24	)	(4.3	)%
Ending Inventory Costs Per Thermal Ton	$	52.26	$	51.55	$	0.71		1.4	%
Total Costs Per Thermal Ton Sold	$	49.57	$	52.06	$	(2.49	)	(4.8	)%
Average Margin Per Thermal Ton Sold	$	9.59	$	9.73	$	(0.14	)	(1.4	)%

Thermal coal revenue was $2,212 million for the nine months ended September 30, 2013 compared to $2,228 million for the nine months ended September 30, 2012. The $16 million decrease was attributable to a $2.63 per ton lower average sales price offset, in part, by a 1.4 million increase in tons sold. The lower average thermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013. The decrease in price was partially offset by 2.4 million tons of thermal coal being priced on the export market at an average sales price of $62.47 per ton for the nine months ended September 30, 2013 compared to 4.1 million tons at an average price of $58.10 per ton for the nine months ended September 30, 2012.

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.

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for thermal coal was $1,854 million for the nine months ended September 30, 2013, or $23 million lower than the $1,877 million for the nine months ended September 30, 2012. Total cost of goods sold for thermal coal was $49.57 per ton in the nine months ended September 30, 2013 compared to $52.06 per ton in the nine months ended September 30, 2012. The decrease in total dollars and unit costs per thermal ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the thermal coal segment were $1,154 million in the nine months ended September 30, 2013 compared to $1,135 million in the nine months ended September 30, 2012. Direct operating costs were $30.98 per ton produced in the current period compared to $31.68 per ton produced in the prior period. Changes in the average direct operating costs per thermal ton produced were primarily related to the following items:

• Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

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• On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. This resulted in lower direct operating costs in the 2013 period or an improvement in the period-to-period comparisons.

• The Blacksville No. 2 Mine was idled in 2013 until May 20th due to the fire that was previously discussed. This resulted in a reduction in all direct operating costs in the current period, as well as a majority of the unit costs.

• The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.

• In 2013, CONSOL Energy entered into several new longwall leases which resulted in higher cost per ton produced in the period-to-period comparison.

• In response to weak market conditions for domestic coal, the annual miner's vacation period at Blacksville No. 2 and Robinson Run mines was extended for a period of two weeks in July 2012. This did not occur in the 2013 period.

Royalties and production taxes increased $1 million to $153 million in the current period. Total dollars increased due to the increase in production volumes, but was offset by the lower average sales prices which is the basis for most production taxes. The unit costs per thermal ton produced decreased $0.14 per ton to $4.11 per ton sold, due to the increase in production volumes.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The cost of these support services was $183 million in the current period compared to $210 million in the prior period. Direct services to the operations were $4.90 per ton produced in the current period compared to $5.89 per ton produced in the prior period. Changes in the average direct service to operations cost per thermal ton produced were primarily related to the following items:

• Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison.

• Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, that was discussed previously.

• Unit costs decreased due to the increase in production volumes since fixed costs are spread over more tons.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the thermal coal segment were $133 million for the nine months ended September 30, 2013 and September 30, 2012. Average cost per thermal ton produced decreased $0.15 per ton to $3.56 per ton sold due to the increase in production volumes.

Depreciation, depletion and amortization for the thermal coal segment was $224 million for the nine months ended September 30, 2013 compared to $225 million for the nine months ended September 30, 2012. Unit costs per thermal ton produced decreased $0.26 in the period-to-period comparison to $6.02. Total dollars and unit costs decreased primarily due to the idling of the Blacksville #2 mine in the 2013 period, as a result of the fire that was previously discussed. The decrease was offset, in part, by lower amortization and depletion for the 2012 period due to the structural failure that affected production at both the Bailey and Enlow Fork Mines. Also, unit costs improved due to the increase in production volumes.

Changes in thermal coal inventory volumes and carrying value resulted in $7 million of cost of goods sold in the nine months ended September 30, 2013 compared to $22 million of cost of goods sold in the nine months ended September 30, 2012. Thermal coal inventory was 1.0 million tons at September 30, 2013 compared to 1.3 million tons at September 30, 2012.

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HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $37 million to total Company earnings before income tax for the nine months ended September 30, 2013 compared to $45 million for the nine months ended September 30, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	2.3		2.9		(0.6		)	(20.7	)%
Average Sales Price Per High Vol Met Ton Sold	$	63.68	$	62.64	$	1.04		1.7	%
Beginning Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%
Total Direct Operating Costs Per High Vol Met Ton Produced	$	31.44	$	29.30	$	2.14		7.3	%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	1.79		3.15		(1.36		)	(43.2	)%
Total Direct Services to Operations Per High Vol Met Ton Produced	5.72		6.42		(0.70		)	(10.9	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.27		3.15		0.12			3.8	%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.95		6.54		(0.59		)	(9.0	)%
Total Production Costs Per High Vol Met Ton Produced	$	48.17	$	48.56	$	(0.39	)	(0.8	)%
Ending Inventory Costs Per High Vol Met Ton	$	—	$	—	$	—		—	%
Total Costs Per High Vol Met Ton Sold	$	48.17	$	49.44	$	(1.27	)	(2.6	)%
Margin Per High Vol Met Ton Sold	$	15.51	$	13.20	$	2.31		17.5	%

High volatile metallurgical coal revenue was $145 million for the nine months ended September 30, 2013 compared to $180 million for the nine months ended September 30, 2012. Average sales prices for high volatile metallurgical coal increased $1.04 per ton in a period-to-period comparison. CONSOL Energy priced 2.1 million tons of high volatile metallurgical coal in the export market at an average sales price of $61.79 per ton for the nine months ended September 30, 2013 compared to 2.5 million tons at an average price of $60.10 per ton for the nine months ended September 30, 2012. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

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

Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $110 million for the nine months ended September 30, 2013, or $32 million lower than the $142 million for the nine months ended September 30, 2012. Total cost of goods sold for high volatile metallurgical coal was $48.17 per ton in the nine months ended September 30, 2013 compared to $49.44 per ton in the nine months ended September 30, 2012. The decrease in total dollars and unit costs per high volatile metallurgical ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the high volatile metallurgical coal segment were $72 million in the nine months ended September 30, 2013 compared to $84 million in the nine months ended September 30, 2012. The reduction in total dollars was primarily due to a reduction in mine maintenance and supply expense as a result of the shutdown of the Fola Mining Complex in August 2012, along with the mix of mines which sold on the high volatile coal market in the period-to-period comparison. Direct operating costs were $31.44 per ton produced in the current period compared to $29.30 per ton produced in the prior period. The increase in the average direct operating costs per high volatile metallurgical ton produced was primarily due to 0.6 million fewer tons produced. This resulted in fixed costs being allocated over less tons, resulting in higher unit costs.

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Royalties and production taxes were $4 million or improved $5 million in the current period primarily due to the shutdown of the Fola Mining Complex in August 2012 and the mix of mines which sold on the high volatile metallurgical coal market. Mines with higher royalty rates produced a larger portion of the high volatile metallurgical coal shipped in the prior period compared to the current period. Unit costs decreased due to the decrease in total dollars and were offset by the lower volumes produced.

Direct services to operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for high volatile metallurgical coal were $13 million in the current period compared to $19 million in the prior period. Direct services to the operations for high volatile metallurgical coal were $5.72 per ton in the current period compared to $6.42 per ton in the prior period. Changes in the average direct services to operations cost per ton for high volatile metallurgical coal produced were primarily related to the following items:

• Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison. The decrease in unit costs was offset by the reduction in production tons.

• Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, which was discussed previously. The decrease in unit costs was also offset by the reduction in production tons.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the high volatile metallurgical coal segment were $7 million for the nine months ended September 30, 2013 compared to $9 million for the nine months ended September 30, 2012. The decrease in total high volatile metallurgical coal retirement and disability total dollars was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after September 30, 2012. Unit costs increased due to the reduction in production tons.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $14 million for the nine months ended September 30, 2013 and $19 million for the nine months ended September 30, 2012. Total dollars and unit costs per high volatile metallurgical ton produced were lower in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 due to the 0.6 million decrease in production tons which resulted in lower depletion expense. The reduction in tons was primarily due to the shutdown of the Fola Mining Complex in August 2012.

There were no changes in volumes or carrying value of coal inventory in the nine months ended September 30, 2013 and September 30, 2012. There was no high volatile metallurgical coal inventory at September 30, 2013 or September 30, 2012.

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LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $107 million to total Company earnings before income tax in the nine months ended September 30, 2013 compared to $165 million in the nine months ended September 30, 2012. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	3.7		2.8		0.9			32.1	%
Average Sales Price Per Low Vol Met Ton Sold	$	95.89	$	143.30	$	(47.41	)	(33.1	)%
Beginning Inventory Costs Per Low Vol Met Ton	$	86.38	$	67.60	$	18.78		27.8	%
Total Direct Operating Costs Per Low Vol Met Ton Produced	$	41.00	$	54.00	$	(13.00	)	(24.1	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.60		8.66		(3.06		)	(35.3	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.20		5.76		(0.56		)	(9.7	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.42		7.90		(2.48		)	(31.4	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.55		10.10		(1.55		)	(15.3	)%
Total Production Costs Per Low Vol Met Ton Produced	$	65.77	$	86.42	$	(20.65	)	(23.9	)%
Ending Inventory Costs Per Low Vol Met Ton	$	65.42	$	87.32	$	(21.90	)	(25.1	)%
Total Costs Per Low Vol Met Ton Sold	$	67.12	$	84.75	$	(17.63	)	(20.8	)%
Margin Per Low Vol Met Ton Sold	$	28.77	$	58.55	$	(29.78	)	(50.9	)%

Low volatile metallurgical coal revenue was $356 million for the nine months ended September 30, 2013 compared to $403 million for the nine months ended September 30, 2012. The $47 million decrease was primarily attributable to a $47.41 per ton lower average sales price. The average sales price for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. For the 2013 period, 2.8 million tons of low volatile metallurgical coal were priced on the export market at an average price of $86.30 per ton compared to 2.1 million tons at an average price of $130.56 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal was $249 million for the nine months ended September 30, 2013, or $11 million higher than the $238 million for the nine months ended September 30, 2012. Total cost of goods sold for low volatile metallurgical coal was $67.12 per ton in the nine months ended September 30, 2013 compared to $84.75 per ton in the nine months ended September 30, 2012. The increase in total dollars and decrease in unit costs per low volatile metallurgical ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power 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. Direct operating costs related to the low volatile metallurgical coal segment were $147 million in the nine months ended September 30, 2013 compared to $160 million in the nine months ended September 30, 2012. Direct operating costs improved primarily as the result of several cost saving initiatives at the Buchanan Mine, such as, slowing the pace of major maintenance projects, right sizing the workforce to fit the recently implemented five-day work schedule, and opening the Horn Mountain portal, which allowed employees to enter the mine much closer to the longwall face. The improvement was partially offset by lower direct operating costs in the 2012 period due to the Buchanan Mine longwall being temporarily idled in March and April. Direct operating costs were $41.00 per ton produced in the current period compared to $54.00 per ton produced in the prior period. Low volatile metallurgical coal production was 0.9 million tons higher in the current period primarily due to Buchanan Mine being temporarily idled in the 2012 period, as mentioned above.

Royalties and production taxes improved $5 million to $20 million in the current period compared to $25 million in the prior period. Unit costs also improved $3.06 per low volatile metallurgical ton produced to $5.60 per ton produced in the

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current period compared to $8.66 per ton produced in the prior period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes, primarily related to the lower average sales price.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for low volatile metallurgical coal were $18 million in the current period and $17 million in the prior period. Direct services to operations for low volatile metallurgical coal were $5.20 per ton produced in the current period compared to $5.76 per ton produced in the prior period. Changes in the average direct services to operations cost per ton for low volatile metallurgical coal produced were due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan. This, coupled with the increase in volumes, resulted in an improvement in the unit costs of $0.56 in the period-to-period comparison.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. 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. The retirement and disability costs attributable to the low volatile metallurgical coal segment were $20 million for the nine months ended September 30, 2013 compared to $23 million for the nine months ended September 30, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-employment benefit plan that occurred on September 30, 2012. This, coupled with the increase in volumes, resulted in an improvement in the unit costs of $2.48 in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $30 million for the nine months ended September 30, 2013 and for the nine months ended September 30, 2012. Unit costs per low volatile metallurgical ton produced were $1.55 lower in the current period due to the 0.9 million increase in production tons.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of $14 million to cost of goods sold in the nine months ended September 30, 2013 and a decrease of $17 million to cost of goods sold in the nine months ended September 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at September 30, 2013 compared to 0.4 million tons at September 30, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $259 million for the nine months ended September 30, 2013 and had a loss before income tax of $135 million for the nine months ended September 30, 2012. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the nine months ended September 30, 2012. No coal was recovered during the reclamation process at idled facilities for the nine months ended September 30, 2013. 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 and coal purchased from third parties and sold directly to our customers. The revenues were $18 million for the nine months ended September 30, 2013 compared to $13 million for the nine months ended September 30, 2012.

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 by freight expense. Freight revenue was $36 million for the nine months ended September 30, 2013 compared to $126 million for the nine months ended September 30, 2012. The $90 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

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Miscellaneous other income was $85 million for the nine months ended September 30, 2013 compared to $229 million for the nine months ended September 30, 2012. The $144 million decrease is due to the following items:

• Gain on sale of assets attributable to the Other Coal segment was $46 million in the nine months ended September 30, 2013 compared to $181 million in the nine months ended September 30, 2012. The decrease of $135 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in income of $22 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in income of $25 million and the sale of 50% interest in a joint venture in Alberta, Canada that resulted in income of $15 million. See Note 2—Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of these sales. The remaining $2 million decrease was related to various transactions that occurred throughout both periods, none of which were individually material.

• Equity in earnings of affiliates decreased $1 million due to lower earnings from our equity affiliates.

• In the nine months ended September 30, 2012, there was an additional $12 million in income that was related to certain thermal coal contract buyouts. There were no such items in the nine months ended September 30, 2013.

• In the nine months ended September 30, 2013, $5 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyor accident. There is no assurance that additional proceeds from the incident will be received.

• The remaining $1 million decrease in other income is due to various items, none of which were individually material.

Other coal segment total costs were $398 million for the nine months ended September 30, 2013 compared to $509 million for the nine months ended September 30, 2012. The decrease of $111 million was due to the following items:

	For the Nine Months Ended September 30,
	2013		2012		Variance
Freight Expense	$	36	$	126	$	(90	)
Bailey Belt Incident	—		42		(42		)
Closed and Idle Mines	101		111		(10		)
General and Administrative Expense	55		60		(5		)
Purchased Coal	32		28		4
Stock-based Compensation	32		24		8
Blacksville No. 2 Mine Fire	39		—		39
Other	103		118		(15		)
Total Other Coal Segment Costs	$	398	$	509	$	(111	)

• Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

• Bailey Belt Incident costs represent expenses during the belt-reconstruction period related to continued advancement of the mines and on-going projects at the mines.

• Closed and idle mine costs decreased approximately $10 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.  There was a $20 million decrease due to the shutdown of the Fola Mining Complex in August 2012. This was offset by an increase in the reclamation liability at the Fola Mining Complex in the June 2012 period due to new regulatory requirements and water and selenium treatment estimates. The decrease was also offset, in part, by an increase of $7 million in costs incurred primarily by the Amonate Complex. The remaining increase of $3 million was 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.

• General and Administrative Expense related to the other coal segment decreased by $5 million primarily due various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section "Net Income" of this quarterly report for detailed costs explanations.

• Purchased coal costs increased due to higher amounts of coal that was purchased to fulfill various contracts.

• Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense and accelerated non-cash amortization for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program.  The new program replaces several previously provided long-term

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executive compensation award programs.  The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.

• The Blacksville No. 2 Mine fire expense was due to a fire that occurred on March 12, 2013. The mine resumed production on May 20, 2013. Insurance recovery is uncertain at this time and the impact of any potential additional recovery has not been reflected in the nine months ended September 30, 2013.

• Other expenses related to the coal segment decreased $15 million due to various transactions that occurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012:

The gas segment had a loss of $7 million before income tax in the nine months ended September 30, 2013 compared to earnings of $25 million in the nine months ended September 30, 2012.

	For the Nine Months Ended													Difference to Nine Months Ended
	September 30, 2013													September 30, 2012
	CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	255	$	99		$	167	$	11		$	532		$	(26	)	$	(2	)	$	83	$	4		$	59
Related Party	2		—			—		—			2			—			—			—		—			—
Total Outside Sales	257		99			167		11			534			(26		)	(2		)	83		4			59
Gas Royalty Interest	—		—			—		47			47			—			—			—		12			12
Purchased Gas			—			—		4			4			—			—			—		2			2
Other Income	—		—			—		37			37			—			—			—		(9		)	(9		)
Total Revenue and Other Income	257		99			167		99			622			(26		)	(2		)	83		9			64
Lifting	27		26			14		4			71			(1		)	(5		)	5		3			2
Ad Valorem, Severance, and Other Taxes	7		7			6		—			20			—			—			3		(2		)	1
Gathering	85		26			30		3			144			7			8			13		3			31
Gas Direct Administrative, Selling & Other	6		7			19		3			35			(6		)	(4		)	9		—			(1		)
Depreciation, Depletion and Amortization	68		44			45		6			163			2			—			14		(1		)	15
General & Administration	—		—			—		33			33			—			—			—		4			4
Gas Royalty Interest	—		—			—		38			38			—			—			—		10			10
Purchased Gas	—		—			—		3			3			—			—			—		1			1
Exploration and Other Costs	—		—			—		44			44			—			—			—		15			15
Other Corporate Expenses	—		—			—		72			72			—			—			—		16			16
Interest Expense	—		—			—		6			6			—			—			—		2			2
Total Cost	193		110			114		212			629			2			(1		)	44		51			96
Earnings Before Income Tax	$	64	$	(11	)	$	53	$	(113	)	$	(7	)	$	(28	)	$	(1	)	$	39	$	(42	)	$	(32	)

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COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $64 million to the total Company earnings before income tax for the nine months ended September 30, 2013 compared to $92 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	62.6		66.8		(4.2		)	(6.3	)%
Average CBM sales price per thousand cubic feet sold	$	4.11	$	4.24	$	(0.13	)	(3.1	)%
Average CBM lifting costs per thousand cubic feet sold	0.44		0.42		0.02			4.8	%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.10		0.11		(0.01		)	(9.1	)%
Average CBM gathering costs per thousand cubic feet sold	1.36		1.17		0.19			16.2	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.10		0.18		(0.08		)	(44.4	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.08		0.99		0.09			9.1	%
Total Average CBM costs per thousand cubic feet sold	3.08		2.87		0.21			7.3	%
Average Margin for CBM	$	1.03	$	1.37	$	(0.34	)	(24.8	)%

CBM sales revenues were $257 million in the nine months ended September 30, 2013 compared to $283 million for the nine months ended September 30, 2012. The $26 million decrease was primarily due to a 6.3% decrease in volumes sold and a 3.1% decrease in average sales price per thousand cubic feet sold. CBM sales volumes decreased 4.2 billion cubic feet for the nine months ended September 30, 2013 compared to the 2012 period primarily due to normal well declines and fewer CBM wells being drilled. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage. The decrease in CBM average sales price was the result of higher average market prices offset by various gas swap transactions that matured 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 34.4 billion cubic feet of our produced CBM gas sales volumes for the nine months ended September 30, 2013 at an average price of $4.56 per thousand cubic feet. For the nine months ended September 30, 2012, these financial hedges represented 34.5 billion cubic feet at an average price of $5.34 per thousand cubic feet.

Total costs for the CBM segment were $193 million for the nine months ended September 30, 2013 compared to $191 million for the nine months ended September 30, 2012. The increase in total dollars and unit costs for the CBM segment are due to the following items:

•CBM lifting costs were $27 million for the nine months ended September 30, 2013 compared to $28 million for the nine months ended September 30, 2012. The decrease in total dollars and unit costs was primarily due to lower road maintenance and lower contractor services in the period-to-period comparison. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes remained consistent at $7 million for the nine months ended September 30, 2013 and 2012.

•CBM gathering costs were $85 million for the nine months ended September 30, 2013 compared to $78 million for the nine months ended September 30, 2012. This increase in total dollars and average per unit costs was due to increased transportation costs, increased power fees, and increased pipeline and road maintenance. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $6 million for the nine months ended September 30, 2013 compared to $12 million for the nine months ended September 30, 2012. 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 decrease in direct administrative, selling & other costs was primarily due to reduced direct administrative labor and CBM volumes representing a smaller proportion of total natural gas volumes sold. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

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•Depreciation, depletion and amortization attributable to the CBM segment was $68 million for the nine months ended September 30, 2013 compared to $66 million for the nine months ended September 30, 2012. There was approximately $47 million, or $0.75 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2013. The production portion of depreciation, depletion and amortization was $45 million, or $0.68 per unit-of-production in the nine months ended September 30, 2012. There was approximately $21 million, or $0.33 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the nine months ended September 30, 2013. The non-production related depreciation, depletion and amortization was $21 million, or $0.31 per thousand cubic feet for the nine months ended September 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $11 million for the nine months ended September 30, 2013 compared to a loss before income tax of $10 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	20.6			21.8			(1.2		)	(5.5	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	4.81		$	4.62		$	0.19		4.1	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.27			1.40			(0.13		)	(9.3	)%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.36			0.34			0.02			5.9	%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.26			0.81			0.45			55.6	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.34			0.49			(0.15		)	(30.6	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.16			2.02			0.14			6.9	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.39			5.06			0.33			6.5	%
Average Margin for Shallow Oil and Gas	$	(0.58	)	$	(0.44	)	$	(0.14	)	31.8	%

Shallow Oil and Gas sales revenues were $99 million for the nine months ended September 30, 2013 compared to $101 million for the nine months ended September 30, 2012. The $2 million decrease was primarily due to the 5.5% decrease in volumes sold, offset, in part, by a 4.1% increase in the average sales price. The increase in shallow oil and gas average sales price is the result of higher average market prices partially offset by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 10.6 billion cubic feet of our produced shallow oil and gas sales volumes for the nine months ended September 30, 2013 at an average price of $5.21 per thousand cubic feet. For the nine months ended September 30, 2012, these financial hedges represented 14.3 billion cubic feet at an average price of $5.23 per thousand cubic feet.

Total costs for the shallow oil and gas segment were $110 million for the nine months ended September 30, 2013 compared to $111 million for the nine months ended September 30, 2012. The decrease in total dollars and increase in unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $26 million for the nine months ended September 30, 2013 compared to $31 million for the nine months ended September 30, 2012. The $5 million decrease in total costs and $0.13 per thousand cubic feet decrease in average unit costs is due to lower road maintenance, lower salt water disposal costs and lower contract services in the current period offset, in part, by an increase in accretion expense on the well plugging liability. The decrease in unit costs is offset, in part, by the decrease in gas volumes sold.

•Shallow Oil and Gas ad valorem, severance and other taxes were $7 million for the nine months ended September 30, 2013 and 2012. The $0.02 per thousand cubic feet increase to average unit costs was primarily due to lower gas volumes sold in the period-to-period comparison.

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•Shallow Oil and Gas gathering costs were $26 million for the nine months ended September 30, 2013 compared to $18 million for the nine months ended September 30, 2012. Gathering costs increased $8 million primarily due to increased firm transportation costs in the period-to-period comparison. Unit costs were further impacted by lower volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $7 million for the nine months ended September 30, 2013 compared to $11 million for the nine months ended September 30, 2012. Direct administrative, selling and 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 $4 million decrease in the period-to-period comparison is due to reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes sold. The decrease in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization costs remained consistent at $44 million for the nine months ended September 30, 2013 and 2012. There was approximately $39 million, or $1.89 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 nine months ended September 30, 2013. There was approximately $38 million, or $1.75 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 nine months ended September 30, 2012. There was approximately $5 million, or $0.27 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 nine months ended September 30, 2013. There was $6 million, or $0.26 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 nine months ended September 30, 2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $53 million to the total Company earnings before income tax for the nine months ended September 30, 2013 compared to $14 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	38.5		24.0		14.5			60.4	%
Average Marcellus sales price per thousand cubic feet sold	$	4.35	$	3.48	$	0.87		25.0	%
Average Marcellus lifting costs per thousand cubic feet sold	0.38		0.38		—			—	%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.15		0.13		0.02			15.4	%
Average Marcellus gathering costs per thousand cubic feet sold	0.79		0.64		0.15			23.4	%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.48		0.43		0.05			11.6	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.16		1.30		(0.14		)	(10.8	)%
Total Average Marcellus costs per thousand cubic feet sold	2.96		2.88		0.08			2.8	%
Average Margin for Marcellus	$	1.39	$	0.60	$	0.79		131.7	%

The Marcellus segment sales revenues were $167 million for the nine months ended September 30, 2013 compared to $84 million for the nine months ended September 30, 2012. The $83 million increase is primarily due to a 60.4% increase in volumes sold, and a 25.0% increase in average sales prices in the period-to-period comparison. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program. The increase in Marcellus average sales price was the result of higher market prices and sales of natural gas liquids, offset by various gas swap transactions that matured in the nine months ended September 30, 2013. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 15.2 billion cubic feet of our produced Marcellus gas sales volumes for the nine months ended September 30, 2013 at an average price of $4.69 per thousand cubic feet. For the nine months ended September 30, 2012, these financial hedges represented 8.5 billion cubic feet at an average price of $4.97 per thousand cubic feet.

Total costs for the Marcellus segment were $114 million for the nine months ended September 30, 2013 compared to $70 million for the nine months ended September 30, 2012. The increase in total dollars and unit costs for the Marcellus segment are due to the following items:

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•Marcellus lifting costs were $14 million for the nine months ended September 30, 2013 compared to $9 million for the nine months ended September 30, 2012. The increase primarily relates to an increase in salt water disposal costs, road maintenance costs, and well tending costs. Lifting costs per unit decreased due to higher sales volumes.

•Marcellus ad valorem, severance and other taxes were $6 million for the nine months ended September 30, 2013 compared to $3 million for the nine months ended September 30, 2012. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by higher average gas sales prices and the 60.4% increase in sales volumes during the current period.

•Marcellus gathering costs were $30 million for the nine months ended September 30, 2013 compared to $17 million for the nine months ended September 30, 2012. Total dollars increased due to higher firm transportation costs, increased processing fees associated with natural gas liquids, and the 14.5 billion cubic feet of additional sales volumes. The impact on average unit costs from these increases was offset by higher sales volumes.

•Marcellus direct administrative, selling and other costs were $19 million for the nine months ended September 30, 2013 compared to $10 million for the nine months ended September 30, 2012. Direct administrative, selling and 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 increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of total natural gas volumes. The impact on average unit costs from the increase in direct administrative labor was offset by higher sales volumes.

•Depreciation, depletion and amortization costs were $45 million for the nine months ended September 30, 2013 compared to $31 million for the nine months ended September 30, 2012. There was approximately $44 million, or $1.15 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2013. There was approximately $28 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 nine months ended September 30, 2012. There was approximately $1 million, or $0.01 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the nine months ended September 30, 2013. There was $3 million, or $0.10 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the nine months ended September 30, 2012.

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 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 and the Utica Shale in Ohio. Revenue from these operations were approximately $11 million for the nine months ended September 30, 2013 and $7 million for the nine months ended September 30, 2012. Total costs related to these other sales were $16 million for the nine months ended September 30, 2013 and $13 million for the nine months ended September 30, 2012. A per unit analysis of the other operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. Royalty interest gas sales revenue was $47 million for the nine months ended September 30, 2013 compared to $35 million for the nine months ended September 30, 2012. 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 increase.

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	10.9		13.2		(2.3		)	(17.4	)%
Average Sales Price Per thousand cubic feet	$	4.27	$	2.63	$	1.64		62.4	%

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Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $4 million for the nine months ended September 30, 2013 and $2 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	1.1		0.8		0.3		37.5	%
Average Sales Price Per thousand cubic feet	$	4.12	$	2.90	$	1.22	42.1	%

Other income was $37 million for the nine months ended September 30, 2013 compared to $46 million for the nine months ended September 30, 2012. The $9 million change was primarily due to a decrease in interest income of $12 million relating to the timing of scheduled collections on notes receivable from the Noble joint venture transaction, offset by a $3 million increase related to increased earnings from our equity affiliates.

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 $33 million for the nine months ended September 30, 2013 and $29 million for the nine months ended September 30, 2012. Refer to the discussion of total company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders"of this quarterly report for a detailed cost explanation.

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 $38 million for the nine months ended September 30, 2013 compared to $28 million for the nine months ended September 30, 2012. 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 Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	10.9		13.2		(2.3		)	(17.4	)%
Average Cost Per thousand cubic feet sold	$	3.50	$	2.12	$	1.38		65.1	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $3 million for the nine months ended September 30, 2013 and $2 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013		2012		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	1.1		1.0		0.1		10.0	%
Average Cost Per thousand cubic feet sold	$	2.79	$	2.22	$	0.57	25.7	%

Exploration and other costs were $44 million for the nine months ended September 30, 2013 compared to $29 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Marcellus Title Defects	$	22	$	2	$	20		1,000.0	%
Lease Expiration Costs	6		13		(7		)	(53.8	)%
Exploration	16		14		2			14.3	%
Total Exploration and Other Costs	$	44	$	29	$	15		51.7	%

• CONSOL Energy has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a book value to CONSOL Energy of $22

79

million for the nine months ended September 30, 2013 compared to $2 million for the nine months ended September 30, 2012.

• Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $7 million decrease is due to CONSOL Energy allowing fewer leases to expire in the current period when compared with the prior period.

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

Other corporate expenses were $72 million for the nine months ended September 30, 2013 compared to $56 million for the nine months ended September 30, 2012. The $16 million increase in the period-to-period comparison was made up of the following items:

	For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change
Unutilized firm transportation	$	25	$	9	$	16		177.8	%
Stock-based compensation	19		15		4			26.7	%
Short-term incentive compensation	16		19		(3		)	(15.8	)%
Bank fees	5		5		—			—	%
Legal fees	2		3		(1		)	(33.3	)%
PA Impact fees	—		4		(4		)	(100.0	)%
Other	5		1		4			400.0	%
Total Other Corporate Expenses	$	72	$	56	$	16		28.6	%

• Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. . The $16 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

• Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense and accelerated non-cash amortization for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to the prior year's quarter.  The new program replaces several previously provided long-term executive compensation award programs.  The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.

• The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense was lower for the 2013 period compared to the 2012 period due to the lower projected payouts.

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

• Legal fees expense decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

• 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. Ongoing PA impact fees, which relate to current year wells drilled, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.

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

Interest expense related to the gas segment was $6 million for the nine months ended September 30, 2013 compared to $4 million for the nine months ended September 30, 2012. Interest was incurred by the gas segment on the CNX Gas revolving credit facility and a capital lease. The $2 million increase was primarily due to higher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.

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OTHER SEGMENT ANALYSIS for thenine monthsendedSeptember 30, 2013compared to thenine monthsendedSeptember 30, 2012:

The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $227 million for the nine months ended September 30, 2013 compared to a loss before income tax of $153 million for the nine months ended September 30, 2012. The other segment also includes total Company income tax expense of $90 million for the nine months ended September 30, 2013 compared to $60 million for the nine months ended September 30, 2012.

	For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change
Sales—Outside	$	248		$	281		$	(33	)	(11.7	)%
Other Income	13			9			4			44.4	%
Total Revenue	261			290			(29		)	(10.0	)%
Cost of Goods Sold and Other Charges	303			250			53			21.2	%
Depreciation, Depletion & Amortization	19			18			1			5.6	%
Taxes Other Than Income Tax	8			9			(1		)	(11.1	)%
Interest Expense	158			166			(8		)	(4.8	)%
Total Costs	488			443			45			10.2	%
Loss Before Income Tax	(227		)	(153		)	(74		)	48.4	%
Income Tax	90			60			30			50.0	%
Net Loss	$	(317	)	$	(213	)	$	(104	)	48.8	%

Industrial supplies:

Outside sales from industrial supplies were $162 million for the nine months ended September 30, 2013 compared to $192 million for the nine months ended September 30, 2012. The decrease of $30 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $159 million for the nine months ended September 30, 2013 compared to $186 million for the nine months ended September 30, 2012. The decrease of $27 million was primarily related to lower sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Outside sales from transportation operations were $86 million for the nine months ended September 30, 2013 compared to $89 million for the nine months ended September 30, 2012. The decrease of $3 million was primarily attributable to higher per ton thru-put rates offset, in part, by decreased thru-put volumes.

Total costs related to the transportation operations were $73 million for the nine months ended September 30, 2013 compared to $65 million for the nine months ended September 30, 2012. The increase of $8 million was primarily attributable to higher per ton thru-put costs offset, in part, by decreased thru-put volumes.

Miscellaneous other:

Additional other income of $13 million was recognized for the nine months ended September 30, 2013 compared to $9 million for the nine months ended September 30, 2012. The $4 million increase was primarily due to an increase in interest income and various items in both periods, none of which were individually material.

Other corporate costs in the other segment were $256 million for the nine months ended September 30, 2013 compared to $192 million for the nine months ended September 30, 2012. Other corporate costs increased due to the following items:

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	For the Nine Months Ended September 30,
	2013		2012		Variance
Pension Settlement	$	38	$	—	$	38
CNX Gas Shareholder Settlement	19		—		19
Corporate Initiative fees and Other Legal Charges	15		4		11
Bank fees	11		10		1
Interest Expense	158		166		(8		)
Other	15		12		3
	$	256	$	192	$	64

• Pension settlement expenses were required when the lump sum distributions made for the 2013 plan year exceeded the total of the service and interest costs for the 2013 plan year.

• The CNX Gas shareholder settlement is the result of an agreement in principle for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provides for a payment to the plaintiffs of $42.73 million, of which the Company expects to pay $18.8 million. This settlement is subject to court approval and to the execution of final agreements with the parties.

• Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. See Note 8 - Property, Plant and Equipment and Note 11 - Commitments and Contingencies of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.

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

• Interest expense decreased $8 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.

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

Income Taxes:

The effective income tax rate was 809.9% for the nine months ended September 30, 2013 compared to 20.2% for the nine months ended September 30, 2012. The effective rates for the nine months ended September 30, 2013 and 2012 were calculated using the annual effective rate projection on recurring earnings and include tax liabilities related to certain discrete transactions. The $90 million of tax expense for the year reflects the Company’s expectation of minimal pre-tax income, excluding gain on sales of assets, for 2013 without a corresponding decrease in excess percentage depletion benefits generated by the Coal division. When pre-tax earnings, excluding gain on sales of assets, approaches breakeven without corresponding reductions in excess percentage depletion, effective tax rates calculated under accounting guidance for interim periods produce results that are not necessarily indicative of the expected tax expense/benefits of the annual period. See Note 5—Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information. 

	For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	11		$	299		$	(288	)	(96.4	)%
Income Tax Expense	$	90		$	60		$	30		49.6	%
Effective Income Tax Rate	809.9		%	20.2		%	789.7		%

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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. 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 $1.5 billion of 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 interest coverage ratio is calculated as the ratio of EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 3.96 to 1.00 at September 30, 2013. The facility includes a maximum leverage ratio covenant of no more than 4.50 to 1.00, measured quarterly. The leverage ratio 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 3.21 to 1.00 at September 30, 2013. 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 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 0.11 to 1.00 at September 30, 2013. 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 September 30, 2013, the facility had no outstanding borrowings and $104 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 or LIBOR plus a charge for administrative services paid to financial institutions. At September 30, 2013, eligible accounts receivable totaled approximately $200 million. At September 30, 2013, the facility had $44 million of outstanding borrowings and $156 million of letters of credit outstanding.

CNX Gas' $1.0 billion 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 $1.0 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 interest coverage ratio is calculated as the ratio of EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 28.55 to 1.00 at September 30, 2013. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The leverage ratio 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 0.75 to 1.00 at September 30, 2013. 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 CONE are unrestricted. At September 30, 2013, the facility had $47 million drawn and $70 million of letters of credit outstanding, leaving $883 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 regularly

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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 $102 million at September 30, 2013. The ineffective portion of these contracts was a gain of $2.6 million and a loss of $120 thousand during the three and nine months ended September 30, 2013. 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 in the future on terms which CONSOL Energy finds acceptable, or at all.

Cash Flows (in millions)

	For the Nine Months Ended September 30,
	2013			2012			Change
Cash flows from operating activities	$	589		$	530		$	59
Cash used in investing activities	$	(560	)	$	(587	)	$	27
Cash used in financing activities	$	(30	)	$	(88	)	$	58

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

• Operating cash flow decreased $317 million in 2013 due to lower net income in the period-to-period comparison.

• Operating cash flows increased $137 million in the period-to-period comparison due to changes in the gains on the sale of assets. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional details.

• Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods also contributed to the increase in operating cash flows.

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

• Capital expenditures increased $44 million in the period-to-period comparison due to:

◦ Coal segment capital expenditures decreased $187 million. The decrease was comprised of $69 million related to the completion of the Northern West Virginia RO system as well as a $27 million decrease in Bailey Mine Expansion projects. Longwall shield projects decreased $23 million as well as an additional $62 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material. Mineral lease expenditures associated with our advance mining royalties and leased coal assets also decreased $6 million in 2013.

◦ Gas segment capital expenditures increased $261 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions in Monroe and Noble Counties in Ohio, and various other individually insignificant projects;

◦ Other capital expenditures decreased $30 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

• Proceeds from the sale of assets increased $14 million in the period-to-period comparison due to:

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◦ $25 million received in August 2013 related to the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada;

◦ $25 million received in June 2013 related to the sale of Potomac Coal reserves;

◦ $68 million received in May 2013 related to the Robinson Run longwall shield sale-leaseback;

◦ $64 million received in March 2013 related to the Shoemaker Mine longwall shield sale-leaseback;

◦ $71 million received in January 2013 related to the Bailey Mine longwall shield sale-leaseback;

◦ $170 million received in June 2012 related to the sale of Youngs Creek;

◦ $26 million received in April 2012 related to sale of Elk Creek;

◦ $13 million received in February 2012 related to the sale of the Burning Star No. 4 property; and

◦ $30 million decrease due to various other transactions that occurred throughout both periods, none of which were individually material.

◦ See Note 2 - Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information.

• Distributions from/investments in equity affiliates increased $1 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

• Restricted cash increased $56 million due to the release of $69 million of restricted cash of which $48 million is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012 and $21 million is associated with the Ryerson Dam Settlement. This was offset by the additional $12 million of restricted cash associated with the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada in August 2013.

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

• In 2013, CONSOL Energy received $47 million of short term borrowings under the revolving credit facilities.

• In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy repaid $7 million of borrowings.

• The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in the first quarter of 2013. Dividends paid in the second and third quarter 2013 were $29 million and $28 million, respectively. This is compared to $85 million in dividends paid in the nine months ended September 30, 2012.

• In 2013, CONSOL Energy received $7 million of borrowing under its Securitization Facility.

• The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.

The following is a summary of our significant contractual obligations at September 30, 2013 (in thousands):

	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	47,000	$	—	$	—	$	—	$	47,000
Borrowings Under Securitization Facility	44,364		—		—		—		44,364
Purchase Order Firm Commitments	308,396		98,652		60,686		30,240		497,974
Gas Firm Transportation	85,313		154,373		128,452		389,000		757,138
Long-Term Debt	4,606		8,537		1,504,927		1,610,291		3,128,361
Interest on Long-Term Debt	245,406		491,245		370,956		296,427		1,404,034
Capital (Finance) Lease Obligations	8,576		15,280		12,464		20,424		56,744
Interest on Capital (Finance) Lease Obligations	3,647		5,666		3,942		2,440		15,695
Operating Lease Obligations	134,204		244,544		171,852		155,729		706,329
Long-Term Liabilities—Employee Related (a)	222,405		442,026		433,053		2,307,138		3,404,622
Other Long-Term Liabilities (b)	369,276		176,349		75,131		515,256		1,136,012
Total Contractual Obligations (c)	$	1,473,193	$	1,636,672	$	2,761,463	$	5,326,945	$	11,198,273

 _________________________

(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

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excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2013 contributions are expected to approximate $50 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 September 30, 2013, CONSOL Energy had total long-term debt and capital lease obligations of $3.185 billion outstanding, including the current portion of long-term debt of $13 million. This long-term debt consisted of:

• An aggregate principal amount of $1.50billion 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 $1.25billion 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 $250million 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 $103million 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.

• Advance royalty commitments of $20million with an average interest rate of 7.43% per annum.

• An aggregate principal amount of $5million on other various rate notes maturing through June 2031.

• An aggregate principal amount of $57million of capital leases with a weighted average interest rate of 6.24%per annum.

At September 30, 2013, CONSOL Energy also had no outstanding borrowings and had approximately $104 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At September 30, 2013, CONSOL Energy had $44 million in outstanding borrowings and had $156 million of letters of credit outstanding under the accounts receivable securitization facility.

At September 30, 2013, CNX Gas, a wholly owned subsidiary of CONSOL Energy, had $47 million in 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 $4.0 billion at September 30, 2013 and at December 31, 2012. Total equity remained consistent in the period-to-period analysis primarily due to a decrease in actuarial liabilities associated with the March 31, 2013, June 30, 2013, and September 30, 2013 pension plan remeasurements, an increase related to stock-based compensation, offset by changes in the fair value of cash flow hedges and treasury stock activity. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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

Declaration Date	Amount Per Share		Record Date	Payment Date
July 26, 2013	$	0.125	August 9, 2013	August 23, 2013
April 26, 2013	$	0.125	May 10, 2013	May 24, 2013
November 1, 2013	$	0.125	November 15, 2013	December 4, 2013

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.40 per share

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when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 3.21 to 1.00 and our availability was approximately $1.4 billion at September 30, 2013. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the nine months ended September 30, 2013.

On October 25, 2013, the Board of Directors approved a change to CONSOL Energy's dividend policy to reflect the Company's increased emphasis on growth. Beginning with the first declared dividend after the transaction with Murray Energy closes, CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share for annual rate of $0.25 per share.

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 of this Form 10-Q. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at September 30, 2013. 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, 2012 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 consolidated balance sheet at September 30, 2013. 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.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended) 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-

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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;

• an extended decline in demand for or 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;

• defects may exist in our chain of title and we may incur additional costs associated with perfecting title for coal or gas rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;

• 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;

• exposure to multi-employer pension plan liabilities;

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

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

• acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated

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changes that could affect assumptions we may have made and divestitures we anticipate may not occur or produce anticipated proceeds;

• the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financial position and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures;

• 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;

• changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate;

• the ability to obtain regulatory approvals for the transaction on the proposed terms and schedule; disruption to our business, including customer, employee and supplier relationships resulting from this transaction; risks that the conditions to closing may not be satisfied; and the impact of the transaction on our future operating results, our capital investment program, and our dividend; and

• other factors discussed in our 2012 Form 10-K under “Risk Factors,” which is on file at the Securities and Exchange Commission.

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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 2012 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2013. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $52.5 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $52.0 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At September 30, 2013, CONSOL Energy had $3.185 billion aggregate principal amount of debt outstanding under fixed-rate instruments and $91 million aggregate principal amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings outstanding at September 30, 2013. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly increased the net loss for the period. CNX Gas’ facility had outstanding borrowings of $47 million at September 30, 2013 and bore interest at a weighted average rate of 1.76% per annum during the nine months ended September 30, 2013. Due to the level of borrowings against this facility and the low weighted average interest rate in the nine months ended September 30, 2013, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly increased the net loss for the period.

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

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Hedging Volumes

As of October 8, 2013, 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
2013 Fixed Price Volumes
Hedged Mcf	N/A		N/A		N/A		23,985,249		23,985,249
Weighted Average Hedge Price per thousand cubic feet	N/A		N/A		N/A		$	4.64	$	4.64
2014 Fixed Price Volumes
Hedged Mcf	18,381,383		18,585,621		18,789,858		18,789,858		74,546,720
Weighted Average Hedge Price per thousand cubic feet	$	4.81	$	4.81	$	4.81	$	4.81	$	4.81
2015 Fixed Price Volumes
Hedged Mcf	15,846,729		16,022,804		16,198,879		16,198,879		64,267,291
Weighted Average Hedge Price per thousand cubic feet	$	4.18	$	4.18	$	4.18	$	4.18	$	4.18
2016 Fixed Price Volumes
Hedged Mcf	13,352,336		13,352,336		13,499,065		13,499,065		53,702,802
Weighted Average Hedge Price per thousand cubic feet	$	4.29	$	4.29	$	4.29	$	4.29	$	4.29

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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 Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2013 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.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The first through the eighteen 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

4.1	Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.00% Senior Notes due 2017.
4.2	Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 8.25% Senior Notes due 2020.
4.3	Supplemental Indenture No. 2, dated as of September 10, 2013, to Indenture dated as of March 9, 2011, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova Scotia Trust Company of New York, with respect to the 6.375 % Senior Notes due 2021.
4.4	Agreement of Resignation, Appointment and Acceptance, dated July 22, 2013, by and among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor Trustee to The Bank of Nova Scotia Trust Company of New York, and The Bank of Nova Scotia Trust Company of New York, as Resigning Trustee (related to the Indenture dated as of April 1, 2010 with respect to the 8.00% Senior Notes due 2017, the Indenture dated as of April 1, 2010 with respect to the 8.25% Senior Notes due 2020, and the Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021).
10.1	Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the 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, Market Street Funding LLC, as Assignor, and PNC Bank, National Association, as Administrator, as LC Bank and as Assignee.
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 September 30, 2013 furnished in XBRL).

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

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SIGNATURES

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

Dated: November 1, 2013

CONSOL ENERGY INC.
By:	/S/    J. BRETT HARVEY
	J. Brett Harvey
	Chairman of the Board and Chief Executive Officer (Duly Authorized Officer and Principal Executive Officer)
By:	/S/    DAVID M. KHANI
	David M. Khani
	Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial Officer)
By:	/S/    LORRAINE L. RITTER
	Lorraine L. Ritter
	Controller and Vice President (Duly Authorized Officer and Principal Accounting Officer)

94

EX-4.1

Execution Copy

SUPPLEMENTAL INDENTURE NO. 4

This SUPPLEMENTAL INDENTURE No. 4 (this "Supplemental Indenture"), dated as of September 10, 2013, among Panda Bamboo Holdings, Inc., a Delaware corporation ("PBH"), Paros Corp., a Delaware corporation ("Paros" and, together with PBH, the "New Subsidiary Guarantors"), each a subsidiary of CONSOL Energy Inc. (or its successor) (the "Company"), CONSOL ENERGY INC., a Delaware corporation, on behalf of itself and the Subsidiary Guarantors (the "Existing Subsidiary Guarantors") under the Indenture referred to below, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as successor trustee to The Bank of Nova Scotia Trust Company of New York, under the indenture referred to below (the "Trustee").

WITNESSETH:

WHEREAS the Company, has heretofore executed and delivered to the Trustee an Indenture (the "Indenture") dated as of April 1, 2010, providing for the issuance of 8.00% Senior Notes Due 2017 (the "Securities"), a Supplemental Indenture dated as of April 30, 2010, a Supplemental Indenture No. 2 dated as of June 16, 2010 and a Supplemental Indenture No. 3 dated as of August 24, 2011;

WHEREAS Section 4.13 of the Indenture provides that under certain circumstances the Company is required to cause the New Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which the New Subsidiary Guarantors shall unconditionally guarantee all of the Company's obligations under the Securities pursuant to a Subsidiary Guarantee on the terms and conditions set forth herein; and

WHEREAS pursuant to Section 9.01 of the Indenture, the Trustee, the Company and Existing Subsidiary Guarantors are authorized to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the New Subsidiary Guarantors, the Company, the Existing Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the holders of the Securities as follows:

1.Definitions.

(a)     Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

(b)    For all purposes of this Supplement, except as otherwise herein expressly provided or unless the context otherwise requires: (i) the terms and expressions used herein shall have the same meanings as corresponding terms and expressions used in the Indenture; and (ii) the words "herein," "hereof" and "hereby" and other words of similar import used in this Supplement refer to this Supplement as a whole and not to any particular section hereof.

2.Agreement to Guarantee. The New Subsidiary Guarantors hereby agree, jointly and severally with all other Subsidiary Guarantors, to guarantee the Company's obligations under the Securities on the terms and subject to the conditions set forth in Article 11 of the Indenture and to be bound by all other applicable provisions of the Indenture.

3.Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every holder of Securities heretofore or hereafter authenticated and delivered shall be bound hereby.

4.Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

5.Trustee Makes No Representation. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture.

6.Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

7.Effect of Headings. The Section headings herein are for convenience only and shall not effect the construction thereof.

[remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date first above written.

NEW SUBSIDIARY GUARANTORS:

Panda Bamboo Holdings, Inc.; and

Paros Corp

by:    /s/ Stephen W. Johnson_________________

Name: Stephen W. Johnson                            Title: Authorized Signatory of each of the                                 New Subsidiary Guarantors listed above

CONSOL ENERGY INC., on behalf of itself and the Existing Subsidiary Guarantors,

by:    /s/ Stephen W. Johnson_________________

Name: Stephen W. Johnson
Title: Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy Inc. and Authorized Signatory of each Existing Subsidiary Guarantor

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee,

by:    /s/ Yana Kislenko_____________________

Name: Yana Kislenko
Title: Vice President

EX-4.2

Execution Copy

SUPPLEMENTAL INDENTURE NO. 4

This SUPPLEMENTAL INDENTURE No. 4 (this "Supplemental Indenture"), dated as of September 10, 2013, among Panda Bamboo Holdings, Inc., a Delaware corporation ("PBH"), Paros Corp., a Delaware corporation ("Paros" and, together with PBH, the "New Subsidiary Guarantors"), each a subsidiary of CONSOL Energy Inc. (or its successor) (the "Company"), CONSOL ENERGY INC., a Delaware corporation, on behalf of itself and the Subsidiary Guarantors (the "Existing Subsidiary Guarantors") under the Indenture referred to below, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as successor trustee to The Bank of Nova Scotia Trust Company of New York, under the indenture referred to below (the "Trustee").

WITNESSETH:

WHEREAS the Company, has heretofore executed and delivered to the Trustee an Indenture (the "Indenture") dated as of April 1, 2010, providing for the issuance of 8.25% Senior Notes Due 2020 (the "Securities"), a Supplemental Indenture dated as of April 30, 2010, a Supplemental Indenture No. 2 dated as of June 16, 2010 and a Supplemental Indenture No. 3 dated as of August 24, 2011;

WHEREAS Section 4.13 of the Indenture provides that under certain circumstances the Company is required to cause the New Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which the New Subsidiary Guarantors shall unconditionally guarantee all of the Company's obligations under the Securities pursuant to a Subsidiary Guarantee on the terms and conditions set forth herein; and

WHEREAS pursuant to Section 9.01 of the Indenture, the Trustee, the Company and Existing Subsidiary Guarantors are authorized to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the New Subsidiary Guarantors, the Company, the Existing Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the holders of the Securities as follows:

1.Definitions.

(a)     Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

(b)    For all purposes of this Supplement, except as otherwise herein expressly provided or unless the context otherwise requires: (i) the terms and expressions used herein shall have the same meanings as corresponding terms and expressions used in the Indenture; and (ii) the words "herein," "hereof" and "hereby" and other words of similar import used in this Supplement refer to this Supplement as a whole and not to any particular section hereof.

2.Agreement to Guarantee. The New Subsidiary Guarantors hereby agree, jointly and severally with all other Subsidiary Guarantors, to guarantee the Company's obligations under the Securities on the terms and subject to the conditions set forth in Article 11 of the Indenture and to be bound by all other applicable provisions of the Indenture.

3.Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every holder of Securities heretofore or hereafter authenticated and delivered shall be bound hereby.

4.Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

5.Trustee Makes No Representation. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture.

6.Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

7.Effect of Headings. The Section headings herein are for convenience only and shall not effect the construction thereof.

[remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date first above written.

NEW SUBSIDIARY GUARANTORS:

Panda Bamboo Holdings, Inc.; and

Paros Corp

by:    /s/ Stephen W. Johnson_________________

Name: Stephen W. Johnson                            Title: Authorized Signatory of each of the                                 New Subsidiary Guarantors listed above

CONSOL ENERGY INC., on behalf of itself and the Existing Subsidiary Guarantors,

by:    /s/ Stephen W. Johnson_________________

Name: Stephen W. JohnsonTitle: Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy Inc. and Authorized Signatory of each Existing Subsidiary Guarantor

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee,

by:    /s/ Yana Kislenko_____________________

Name: Yana Kislenko
Title: Vice President

EX-4.3

Execution Copy

SUPPLEMENTAL INDENTURE NO. 2

This SUPPLEMENTAL INDENTURE No. 2 (this "Supplemental Indenture"), dated as of September 10, 2013, among Panda Bamboo Holdings, Inc., a Delaware corporation ("PBH"), Paros Corp., a Delaware corporation ("Paros" and, together with PBH, the "New Subsidiary Guarantors"), each a subsidiary of CONSOL Energy Inc. (or its successor) (the "Company"), CONSOL ENERGY INC., a Delaware corporation, on behalf of itself and the Subsidiary Guarantors (the "Existing Subsidiary Guarantors") under the Indenture referred to below, and WELLS FARGO BANK, NATIONAL ASSOCIATION, as successor trustee to The Bank of Nova Scotia Trust Company of New York, under the indenture referred to below (the "Trustee").

WITNESSETH:

WHEREAS the Company, has heretofore executed and delivered to the Trustee an Indenture (the "Indenture") dated as of March 9, 2011, providing for the issuance of 6.375% Senior Notes Due 2021 (the "Securities") and a Supplemental Indenture No. 1 dated as of August 24, 2011;

WHEREAS Section 4.13 of the Indenture provides that under certain circumstances the Company is required to cause the New Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which the New Subsidiary Guarantors shall unconditionally guarantee all of the Company's obligations under the Securities pursuant to a Subsidiary Guarantee on the terms and conditions set forth herein; and

WHEREAS pursuant to Section 9.01 of the Indenture, the Trustee, the Company and Existing Subsidiary Guarantors are authorized to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the New Subsidiary Guarantors, the Company, the Existing Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the holders of the Securities as follows:

1.Definitions.

(a)     Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

(b)    For all purposes of this Supplement, except as otherwise herein expressly provided or unless the context otherwise requires: (i) the terms and expressions used herein shall have the same meanings as corresponding terms and expressions used in the Indenture; and (ii) the words "herein," "hereof" and "hereby" and other words of similar import used in this Supplement refer to this Supplement as a whole and not to any particular section hereof.

2.Agreement to Guarantee. The New Subsidiary Guarantors hereby agree, jointly and severally with all other Subsidiary Guarantors, to guarantee the Company's obligations under the Securities on the terms and subject to the conditions set forth in Article 11 of the Indenture and to be bound by all other applicable provisions of the Indenture.

3.Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every holder of Securities heretofore or hereafter authenticated and delivered shall be bound hereby.

4.Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

5.Trustee Makes No Representation. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture.

6.Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

7.Effect of Headings. The Section headings herein are for convenience only and shall not effect the construction thereof.

[remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date first above written.

NEW SUBSIDIARY GUARANTORS:

Panda Bamboo Holdings, Inc.; and

Paros Corp

by:    /s/ Stephen W. Johnson        

Name: Stephen W. Johnson                            Title: Authorized Signatory of each of the                                 New Subsidiary Guarantors listed above

CONSOL ENERGY INC., on behalf of itself and the Existing Subsidiary Guarantors,

by:    /s/ Stephen W. Johnson        

Name: Stephen W. JohnsonTitle: Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy Inc. and Authorized Signatory of each Existing Subsidiary Guarantor

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee,

by:    /s/ Yana Kislenko        

Name: Yana Kislenko
Title: Vice President

EX-4.4

[Execution Version]

AGREEMENT OF RESIGNATION, APPOINTMENT AND ACCEPTANCE (the “Agreement”), dated as of July 22, 2013 by and among CONSOL Energy Inc., a corporation duly organized and existing under the laws of the State of Delaware and having its principal office at 1000 CONSOL Energy Drive, CNX Center, Cononsburg, PA 15317 (the “Company”), certain of the Company’s subsidiaries signatory hereto (each a “Subsidiary Guarantor”),Wells Fargo Bank, National Association, a national banking association validly existing and in good standing under the laws of the United States and having a corporate trust office at 150 East 42^nd Street, 40^th Floor, New York, NY 10017 (“Successor Trustee”) and The Bank of Nova Scotia Trust Company of New York, a banking association duly organized and existing under the laws of the State of New York and having a corporate trust office at One Liberty Plaza, 23^rd Floor, New York, New York 10006 (“Resigning Trustee”).

RECITALS:

WHEREAS, there are currently (i) $1,500,000,000 in aggregate principal amount of the Company’s 8.00% Senior Notes Due 2017 (the “2017 Notes”) outstanding under an Indenture, dated as of April 1, 2010, by and between the Company and Resigning Trustee (as amended and supplemented as of the date hereof, the “2017 Indenture”), (ii) $1,250,000,000 in aggregate principal amount of the Company’s 8.25% Senior Notes Due 2020 (the “2020 Notes”) outstanding under an Indenture, dated as of April 1, 2010, by and between the Company and Resigning Trustee (as amended and supplemented as of the date hereof, the “2020 Indenture”) and (iii) $250,000,000 in aggregate principal amount of the Company’s 6.375% Senior Notes Due 2021 (the “2021 Notes” and, together with the 2017 Notes and the 2020 Notes, the “Securities”) outstanding under an Indenture, dated as of March 9, 2011, by and between the Company and Resigning Trustee (as amended and supplemented as of the date hereof, the “2021 Indenture” and, together with the 2017 Indenture and the 2020 Indenture, the “Indentures” or each an “Indenture”);

WHEREAS, the Company appointed Resigning Trustee as the trustee (the "Trustee"), registrar (the "Registrar") and paying agent (the "Paying Agent") under each Indenture;

WHEREAS, Section 7.08 of each Indenture provides that the Trustee may resign with respect to the related Securities by giving written notice of such resignation to the Company, effective upon the acceptance by a successor Trustee of its appointment as a successor Trustee;

WHEREAS, Section 7.08 of each Indenture provides that, if the Trustee shall resign, the Company shall promptly appoint a successor Trustee;

WHEREAS, Section 7.08 of each Indenture provides that any successor Trustee appointed in accordance with such Indenture shall execute and deliver a written acceptance of its appointment to the Company and Resigning Trustee, and thereupon the resignation of the predecessor Trustee shall become effective and such successor Trustee shall have all the rights, powers, duties of the Trustee under such Indenture;

WHEREAS, Resigning Trustee has given written notice to the Company that it is resigning as Trustee, Registrar and Paying Agent under the Indentures;

WHEREAS, the Company desires to appoint Successor Trustee as successor Trustee, Registrar and Paying Agent to succeed Resigning Trustee in such capacities under the Indentures; and

WHEREAS, Successor Trustee is willing to accept such appointment as successor Trustee, Registrar and Paying Agent under the Indentures;

NOW, THEREFORE, the Company, Resigning Trustee and Successor Trustee, for and in consideration of the premises and of other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, hereby consent and agree as follows:

1
THE RESIGNING TRUSTEE

1.1Pursuant to Section 7.08 of each Indenture, Resigning Trustee has in writing notified the Company that Resigning Trustee is resigning as Trustee, Registrar and Paying Agent under the Indentures.

1.2Resigning Trustee hereby represents and warrants to Successor Trustee that:

(a) The Indentures, and each amendment and supplemental indenture thereto, if any, were validly and lawfully executed and delivered by the Resigning Trustee.

(b) No covenant or condition contained in the Indentures has been waived by Resigning Trustee or, to the best knowledge of responsible officers of Resigning Trustee’s corporate trust department, by the Holders of the percentage in aggregate principal amount of the Securities required by the Indentures to effect any such waiver.

(c) To the best knowledge of responsible officers of Resigning Trustee's corporate trust department, there is no action, suit or proceeding pending or threatened against Resigning Trustee before any court or any governmental authority arising out of any act or omission of Resigning Trustee as Trustee under the Indentures.

(d) As of the effective date of this Agreement, Resigning Trustee will hold no moneys or property under the Indentures.

(e) Pursuant to (i) Section 2.02 of the 2017 Indenture, Resigning Trustee has duly authenticated and delivered $1,500,000,000 in aggregate principal amount of 2017 Notes, (ii) Section 2.02 of the 2020 Indenture, Resigning Trustee has duly authenticated and delivered $1,250,000,000 in aggregate principal amount of 2020 Notes and (iii) Section 2.02 of the 2021 Indenture, Resigning Trustee has duly authenticated and delivered $250,000,000 in aggregate principal amount of 2021 Notes, all of which, to the best knowledge of responsible officers of Resigning Trustee's corporate trust department, are outstanding as of the effective date hereof and interest has been paid, through the most recent date on which interest is required to be paid in accordance with the terms of such Securities.

(f) The registers in which it has registered and transferred registered Securities accurately reflect the amount of Securities issued and outstanding and the amounts payable thereon.

(g) Each person who so authenticated the Securities was duly appointed, qualified and acting as an officer or authorized signatory of Resigning Trustee and empowered to authenticate the Securities at the respective times of such authentication and the signature of such person or persons appearing on such Securities is each such person’s genuine signature.

(h) This Agreement has been duly authorized, executed and delivered on behalf of Resigning Trustee and constitutes its legal, valid and binding obligation, enforceable in accordance with its terms.

(i) Without independent investigation, no responsible officer of the Resigning Trustee's corporate trust department has received notice from the Company or any Holder that a default or Event of Default has occurred and is continuing under any Indenture, and no responsible officer of the Resigning Trustee's corporate trust department has actual knowledge that a default or Event of Default has occurred and is continuing under any Indenture.

1.3As of the effective date hereof, Resigning Trustee assigns, transfers, delivers and confirms to Successor Trustee all right, title and interest of Resigning Trustee in and to the trust under the Indentures and all the rights, powers, trusts, privileges, immunities, duties and obligations of the Trustee under the Indentures. Resigning Trustee shall execute and deliver such further instruments and shall do such other things as Successor Trustee may reasonably require so as to more fully and certainly vest and confirm in Successor Trustee all the rights, powers, trusts, privileges, immunities, duties and obligations hereby assigned, transferred, delivered and confirmed to Successor Trustee as Trustee, Registrar and Paying Agent under the Indentures.

1.4Resigning Trustee shall deliver to Successor Trustee, as of or promptly after the effective date hereof, all of the documents listed on Exhibit A hereto.

2
THE COMPANY

2.1The Company hereby accepts the resignation of Resigning Trustee as Trustee, Registrar and Paying Agent under the Indentures.

2.2The Company hereby appoints Successor Trustee as Trustee, Registrar and Paying Agent under the Indentures to succeed to, and hereby vests Successor Trustee with, all the rights, powers, trusts, privileges, immunities, duties and obligations of Resigning Trustee under the Indentures with like effect as if originally named as Trustee, Registrar and Paying Agent in the Indentures.

2.3Promptly after the effective date of this Agreement, the Company shall cause a notice, substantially in the form of Exhibit B annexed hereto, to be sent to each Holder of the Securities.

2.4The Company hereby represents and warrants to Resigning Trustee and Successor Trustee that:

(a) The Company is a corporation duly and validly organized and existing pursuant to the laws of the State of Delaware.

(b) The Indentures, and each amendment or supplemental indenture thereto, if any, were validly and lawfully executed and delivered by the Company and is in full force and effect and the Securities were validly issued by the Company.

(c) The Company has performed or fulfilled prior to the date hereof, and will continue to perform and fulfill after the date hereof, each covenant, agreement, condition, obligation and responsibility under the Indentures.

(d) No event has occurred and is continuing which is, or after notice or lapse of time or both would become, an Event of Default under any Indenture.

(e) No covenant or condition contained in any Indenture has been waived by the Company or by Holders of the percentage in aggregate principal amount of the Securities required to effect any such waiver.

(f) There is no action, suit or proceeding pending or, to the best of the Company’s knowledge, threatened against the Company before any court or any governmental authority arising out of any act or omission of the Company under any Indenture.

(g) The Company has, by a resolution which was duly adopted by the Board of Directors of the Company, and which is in full force and effect on the date hereof, authorized certain officers of the Company to: (a) accept Resigning Trustee’s resignation as Trustee, Registrar and Paying Agent under the Indentures; (b) appoint Successor Trustee as Trustee, Registrar and Paying Agent under the Indentures; and (c) execute and deliver such agreements, including, without limitation, this Agreement and other instruments as may be necessary or desirable to effectuate the succession of Successor Trustee as Trustee, Registrar and Paying Agent under the Indentures. Furthermore, this Agreement has been duly authorized, executed and delivered on behalf of the Company and constitutes its legal, valid and binding obligation, enforceable in accordance with its terms.

(h) All conditions precedent relating to the appointment of Wells Fargo Bank, National Association as successor Trustee under the Indentures have been complied with by the Company.

3
THE SUCCESSOR TRUSTEE

3.1Successor Trustee hereby represents and warrants to Resigning Trustee and to the Company that:

(a) Successor Trustee is not disqualified under the provisions of Section 7.10 of each Indenture and is eligible under the provisions of Section 7.10 of such Indenture to act as Trustee under such Indenture.

(b) This Agreement has been duly authorized, executed and delivered on behalf of Successor Trustee and constitutes its legal, valid and binding obligation, enforceable in accordance with its terms.

3.2Successor Trustee hereby accepts its appointment as successor Trustee, Registrar and Paying Agent under the Indentures and accepts the rights, powers, trusts, privileges, immunities, duties and obligations of Resigning Trustee as Trustee, Registrar and Paying Agent under the Indentures, upon the terms and conditions set forth therein, with like effect as if originally named as Trustee, Registrar and Paying Agent under the Indentures.

3.3References in the Indentures to “Principal Office” or other similar terms shall be deemed to refer to the designated corporate trust office of Successor Trustee, which is presently located at 150 East 42^nd Street, 40^th Floor, New York, NY 10017.

4
MISCELLANEOUS

4.1Except as otherwise expressly provided herein or unless the context otherwise requires, all capitalized terms used herein which are defined in the Indentures shall have the meanings assigned to them in the Indentures.

4.2This Agreement and the resignation, appointment and acceptance effected hereby shall be effective as of the opening of business on July 22, 2013.

4.3This Agreement does not constitute a waiver by any of the parties hereto of any obligation or liability which Resigning Trustee may have incurred in connection with its serving as Trustee, Paying Agent or Registrar under the Indentures or an assumption by Successor Trustee of any liability of Resigning Trustee arising out of a breach by Resigning Trustee prior to its resignation of its duties under any Indenture. The parties hereto agree that this Agreement does not constitute an assumption by Successor Trustee of any liability of Resigning Trustee arising out of any actions or inaction by Resigning Trustee in performance (or non-performance) of its duties under the Indentures.

4.4Resigning Trustee hereby acknowledges payment or provision for payment in full by the Company of compensation for all services rendered by Resigning Trustee in its capacity as Trustee, Registrar and Paying Agent under Section 7.07 of each Indenture and reimbursement in full by the Company of the expenses, disbursements and advances incurred or made by Resigning Trustee in its capacity as Trustee, Registrar and Paying Agent in accordance with the provisions of each Indenture. Resigning Trustee acknowledges that it relinquishes any lien it may have upon all property or funds held or collected by it to secure any amounts due it pursuant to the provisions of Section 7.07 of such Indenture. This Agreement does not constitute a waiver or assignment by the Resigning Trustee of any compensation, reimbursement, expenses or indemnity to which it is or may be entitled pursuant to the Indentures. The Company acknowledges its obligation set forth in Section 7.07 of each Indenture to indemnify Resigning Trustee against any and all loss, liability or expense (including attorneys’ fees) incurred without willful misconduct, negligence or bad faith on the part of Resigning Trustee and arising out of the acceptance or administration of the trust evidenced by the Indentures (which obligation shall survive the execution hereof).

4.5[Reserved]

4.6This Agreement shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles thereof that would result in the application of the laws of any other jurisdiction.

4.7This Agreement may be executed in any number of counterparts each of which shall be an original, but such counterparts shall together constitute but one and the same instrument. The exchange of copies of this Agreement and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this Agreement as to the parties hereto and may be used in lieu of the original Agreement for all purposes. Signatures of the parties hereto transmitted by facsimile or PDF shall be deemed to be their original signatures for all purposes.

4.8The Company acknowledges that, in accordance with Section 326 of the USA Patriot Act, Successor Trustee, in order to help fight the funding of terrorism and prevent money laundering, is required to obtain, verify and record information that identifies each person or legal entity that establishes a relationship or opens an account with Successor Trustee. The Company agrees that it will provide Successor Trustee with such information as it may request in order for Successor Trustee to satisfy the requirements of the USA Patriot Act.

4.9This Agreement sets forth the entire agreement of the parties with respect to its subject matter, and supersedes and replaces any and all prior contemporaneous warranties, representations or agreements, whether oral or written, with respect to the subject matter of this Agreement other than those contained in this Agreement.

4.10The Company, Resigning Trustee and Successor Trustee hereby acknowledge receipt of an executed counterpart of this Agreement.

4.11    Unless otherwise provided herein, all notices, requests and other communications to any party hereunder shall be in writing (including facsimile and electronic transmission in PDF format) and shall be given to such party, addressed to it, as set forth below:

If to the Company:

CONSOL Energy Inc.1000 CONSOL Energy Drive,

CNX Center,

Cononsburg, PA 15317            
Attention:     John M. Reilly
Facsimile: (724) 485-4825     

Email: JohnReilly@consolenergy.com                

If to Resigning Trustee:

The Bank of Nova Scotia Trust Company of New York

One Liberty Plaza

23^rd Floor

New York, New York 10006

Attention: Trust Administrator

Facsimile: (212) 225-5436

Email: warren.goshine@scotiabank.com

If to Successor Trustee:

Wells Fargo Bank, National Association

150 E. 42^nd Street

40^th Floor

New York, NY 10017

Attention: Corporate Trust Services – Admin for CONSOL Energy Inc.             Facsimile: 917-260-1593

Email: yana.kislenko@wellsfargo.com

[Signature pages to follow]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement of Resignation, Appointment and Acceptance to be duly executed, all as of the day and year first above written.

CONSOL ENERGY INC.

By: /s/ Stephen W. Johnson

Name: Stephen W. Johnson
Title: Executive Vice President and Chief Legal and Corporate Affairs Officer

THE BANK OF NOVA SCOTIA TRUST COMPANY OF NEW YORK,

as Resigning Trustee

By: /s/ Warren A. Goshine

Name: Warren A. Goshine
Title: Vice President

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Successor Trustee

By: /s/ Yana Kislenko

Name: Yana Kislenko
Title: Vice President

EXHIBIT A

Documents to be delivered to Successor Trustee

1. Executed copy of each Indenture and each amendment and supplemental indenture thereto.

2. File of closing documents from initial issuance.

3. Copies of the most recent of each of the SEC reports delivered by the Company pursuant to Section 4.02 of the Indentures, provided that any such reports filed with the EDGAR system of the SEC and available publicly on the internet shall be deemed to be delivered.

4. A copy of the most recent compliance certificate delivered pursuant to Section 4.11 of the Indentures.

5. Certified list of Holders, including certificate detail and all “stop transfers” and the reason for such “stop transfers” (or, alternatively, if there are a substantial number of registered Holders, the computer tape reflecting the identity of such Holders).

6. Copies of any official notices sent by the Trustee to all the Holders of the Securities pursuant to the terms of the Indentures during the past twelve months and a copy of the most recent Trustee’s annual report to Holders delivered pursuant to Section 4.02 of the Indentures.

7. List of any documents which, to the knowledge of Resigning Trustee, are required to be furnished but have not been furnished to Resigning Trustee.

8. All global notes.

9. Securities debt service records.

EXHIBIT B
NOTICE

To the Holders of:

[8.00%][8.25%][6.375%] Senior Notes Due [2017], [2020], [2021]     CUSIP # ____________

of CONSOL ENERGY INC.

NOTICE IS HEREBY GIVEN, pursuant to the Indenture (the “Indenture”), dated as of [April 1, 2010][March 9, 2011], by and between Consol Energy Inc. and The Bank of Nova Scotia Trust Company of New York (“Bank of Nova Scotia”), as Trustee, that Bank of Nova Scotia has resigned as trustee, registrar and paying agent under the Indenture.

Pursuant to Section 7.08 of the Indenture,

Wells Fargo Bank, National Association, a national banking association duly organized and existing under the laws of the United States (“Wells Fargo”), has accepted appointment as trustee, registrar and paying agent under the Indenture. The address of the designated corporate trust office of the successor Trustee is 150 East 42^nd Street, 40^th Floor, New York, NY 10017.

Bank of Nova Scotia’s resignation as trustee, registrar and paying agent and Wells Fargo’s appointment as successor trustee, registrar and paying agent were effective as of the opening of business on July 22, 2013.

Dated: July 22, 2013

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Successor Trustee

By:

Name:
Title:

SCHEDULE I

Subsidiary Guarantors

AMVEST Coal & Rail, L.L.C.AMVEST Coal Sales, Inc.
AMVEST Corporation
AMVEST Gas Resources, Inc.AMVEST Mineral Services, Inc.AMVEST Minerals Company, L.L.C. AMVEST Oil & Gas, Inc.AMVEST West Virginia Coal, L.L.C.Braxton-Clay Land & Mineral, Inc. Cardinal States Gathering Company (by CNX Gas Company LLC and CNX Gas Corporation, its partners) Central Ohio Coal CompanyCNX Gas Company LLC CNX Gas Corporation CNX Land Resources Inc.CNX Marine Terminals Inc. CNX Water Assets LLC

Coalfield Pipeline CompanyConrhein Coal Company (by Consolidation Coal Company and MTB Inc., its partners)CONSOL Energy Holdings LLC VICONSOL Energy Sales CompanyCONSOL Financial Inc. CONSOL of Canada Inc.CONSOL of Central Pennsylvania LLCCONSOL of Kentucky Inc. CONSOL of Ohio LLC Consol Pennsylvania Coal Company LLCConsolidation Coal CompanyEighty-Four Mining CompanyFola Coal Company, L.L.C. Glamorgan Coal Company, L.L.C. Helvetia Coal CompanyIsland Creek Coal Company Keystone Coal Mining Corporation Knox Energy, LLCLaurel Run Mining CompanyLeatherwood, Inc.Little Eagle Coal Company, L.L.C. McElroy Coal CompanyMOB CorporationMon River Towing, Inc.MTB Inc.Nicholas-Clay Land & Mineral, Inc.Peters Creek Mineral Services, Inc. Reserve Coal Properties Company Rochester & Pittsburgh Coal Company Southern Ohio Coal Company TEAGLE Company, L.L.C.TECPART CorporationTerra Firma CompanyTerry Eagle Coal Company, L.L.C.Terry Eagle Limited Partnership (by TEAGLE Company, L.L.C. and TECPART Corporation, its general partners)

Twin Rivers Towing Company Vaughan Railroad Company Windsor Coal Company
Wolfpen Knob Development Company

NY 243171882v2

EX-10.1

EXECUTION COPY

[CONSOL]

NINTH AMENDMENT TO AMENDED AND RESTATED

RECEIVABLES PURCHASE AGREEMENT

THIS NINTH AMENDMENT TO AMENDED AND RESTATED RECEIVABLES PURCHASE AGREEMENT (this “Amendment”), dated as of September 23, 2013, is entered into among CNX FUNDING CORPORATION, (the “Seller”), CONSOL ENERGY INC. (“CONSOL Energy”), as the initial Servicer (in such capacity, the “Servicer”), the various Sub-Servicers listed on the signature pages hereto, the Conduit Purchasers listed on the signature pages hereto, the Purchaser Agents listed on the signature pages hereto, the LC Participants listed on the signature pages hereto, MARKET STREET FUNDING LLC (“Market Street”), as Assignor (as defined below) and PNC BANK, NATIONAL ASSOCIATION (“PNC”), as Administrator (in such capacity, the “Administrator”), as LC Bank (in such capacity, the “LC Bank”) and as Assignee (as defined below).

RECITALS

1.Reference is made to that certain Amended and Restated Receivables Purchase Agreement, dated as of April 30, 2007 (as amended, restated, supplemented or otherwise modified, the “Agreement”) by and among the Seller, the Servicer, the various Sub-Servicers, Conduit Purchasers, Purchaser Agents and LC Participants party thereto, the Administrator and the LC Bank;

2.Concurrently herewith, certain of the parties hereto are entering into a Fee Letter, dated as of the date hereof (the “Fee Letter”);

3.Market Street, as the assignor (in such capacity, the “Assignor”), desires to sell, assign and delegate to PNC, as the assignee (in such capacity, the “Assignee”), all of the Assignor’s rights under, interest in, title to and obligations under the Agreement and the other Transaction Documents (collectively, the “Assigned Documents”), and the Assignee desires to purchase and assume from the Assignor all of the Assignor’s rights under, interest in, title to and obligations under the Assigned Documents;

4.After giving effect to the assignment and assumption contemplated in Section 2 of this Amendment, each of the parties hereto desires that Market Street cease to be a party to the Agreement and each of the other Assigned Documents to which it is a party and to be discharged from its duties and obligations as a Purchaser or otherwise under the Agreement and each of the other Assigned Documents; and

5.The parties hereto desire to amend the Agreement as hereinafter set forth.

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

SECTION 1.Certain Defined Terms. Capitalized terms that are used but not defined herein shall have the meanings set forth in the Agreement.

SECTION 2.Assignment and Assumption.

(a)Sale and Assignment by Assignor to Assignee. At or before 2:00 pm (New York time) on the date hereof, the Assignee shall pay to the Assignor, in immediately available funds, (i) the amount set forth on Schedule I hereto (such amount, the “Capital Payment”) representing 100.00% of the aggregate Capital of the Assignor under the Agreement on the date hereof and (ii) the amount set forth on Schedule I hereto representing all accrued but unpaid (whether or not then due) Discount, fees and other costs and expenses payable in respect of such Capital to but excluding the date hereof (such amount, the “CP Costs and Other Costs”; together with the Capital Payment, collectively, the “Payoff Amount”). Upon the Assignor’s receipt of the Payoff Amount in its entirety, the Assignor hereby sells, transfers, assigns and delegates to the Assignee, without recourse, representation or warranty except as otherwise provided herein, and the Assignee hereby irrevocably purchases, receives, accepts and assumes from the Assignor, all of the Assignor’s rights under, interest in, title to and all its obligations under the Agreement and the other Assigned Documents. Without limiting the generality of the foregoing, the Assignor hereby assigns to the Assignee all of its right, title and interest in the Purchased Interest.

Payment of each portion of the Payoff Amount shall be made by wire transfer of immediately available funds in accordance with the payment instructions set forth on Schedule II hereto.

(b)Removal of Assignor. From and after the Effective Date (as defined below), the Assignor shall cease to be a party to the Agreement and each of the other Assigned Documents to which it was a party and shall no longer have any rights or obligations under the Agreement or any other Assigned Document (other than such rights which by their express terms survive termination thereof).

(c)Limitation on Liability. Notwithstanding anything to the contrary set forth in this Amendment, the Assignee does not accept or assume any liability or responsibility for any breach, failure or other act or omission on the part of the Assignor, or any indemnification or other cost, fee or expense related thereto, in each case which occurred or directly or indirectly arose out of an event which occurred prior to the Effective Date.

(d)Acknowledgement and Agreement.    Each of the parties and signatories hereto (i) hereby acknowledges and agrees to the sale, assignment and assumption set forth in clause (a) above and (ii) expressly waives any notice or other applicable requirements set forth in any Transaction Document as a prerequisite or condition precedent to such sale, assignment and assumption (other than as set forth herein).

SECTION 3.Joinder.

(a)PNC as a Conduit Purchaser. From and after the date hereof, PNC shall be a Conduit Purchaser party to the Agreement for all purposes thereof and of the other Transaction Documents as if PNC were an original party to the Agreement in such capacity, and PNC assumes all related rights and agrees to be bound by all of the terms and provisions applicable to Conduit Purchasers contained in the Agreement and the other Transaction Documents. It being understood and agreed that for purposes of the Agreement and each of the other Transaction Documents, PNC, as a Conduit Purchaser shall be deemed (i) not to have (A) a Liquidity Provider, (B) a Liquidity Agent or (C) a Program Support Provider and (ii) not to issue any Notes or have a commercial paper program. Any reference in the Agreement or any other Transaction Document referring to any Conduit Purchaser’s Liquidity Provider, Liquidity Agent, Program Support Provider, Notes or commercial paper program shall be deemed to apply to each Conduit Purchaser other than PNC. Each reference to the calculation of Discount with respect to PNC as a Conduit Purchaser shall be deemed to be a reference to the calculation of Discount by reference to the Alternative Rate rather than the CP Rate.

(b)Appointment of PNC as Purchaser Agent of PNC’s Purchaser Group. PNC hereby designates itself as, and PNC hereby agrees to perform the duties and obligations of, the Purchaser Agent for PNC’s Purchaser Group. From and after the date hereof, PNC shall be a Purchaser Agent party to the Agreement, for all purposes of the Agreement and the other Transaction Documents as if PNC were an original party to the Agreement in such capacity, and PNC assumes all related rights and agrees to be bound by all of the terms and provisions applicable to Purchaser Agents contained in the Agreement and the other Transaction Documents.

(c)Commitment. The Commitment of PNC under the Agreement as a Conduit Purchaser shall be $110,000,000 unless and until otherwise modified in accordance with the Agreement.

(d)Notice Address. PNC’s address for notices under the Agreement in its capacity as a Conduit Purchaser and as a Purchaser Agent shall be the following:

Address: PNC Bank, National Association

Three PNC Plaza

225 Fifth Avenue

Pittsburgh, Pennsylvania 15222

Attention: Robyn Reeher

Telephone: 412-768-3090

Facsimile: 412-762-9184

SECTION 4.Amendments to the Agreement. The Agreement is hereby amended as follows:

(a)The preamble of the Agreement is hereby replaced in its entirety with the following:

This AMENDED AND RESTATED RECEIVABLES PURCHASE AGREEMENT (as amended, supplemented or otherwise modified from time to time, this “Agreement”) is entered into as of April 30, 2007, by and among CNX FUNDING CORPORATION, a Delaware corporation, as seller (the “Seller”), CONSOL ENERGY INC., a Delaware corporation (“CONSOL Energy”), as initial servicer (in such capacity, together with its successors and permitted assigns in such capacity, the “Servicer”), CONSOL ENERGY SALES COMPANY, a Delaware corporation, CONSOL OF KENTUCKY INC., a Delaware corporation, CONSOL PENNSYLVANIA COAL COMPANY, a Delaware corporation, CONSOLIDATION COAL COMPANY, a Delaware corporation, ISLAND CREEK COAL COMPANY, a Delaware corporation, WINDSOR COAL COMPANY, a West Virginia corporation, MCELROY COAL COMPANY, a Delaware corporation, KEYSTONE COAL MINING CORPORATION, a Pennsylvania corporation, EIGHTY-FOUR MINING COMPANY, a Pennsylvania corporation, and CNX MARINE TERMINALS INC., a Delaware corporation (each a “Sub-Servicer” and collectively, the “Sub-Servicers”), the CONDUIT PURCHASERS PARTY HERETO (each, a “Conduit Purchaser”), the PURCHASER AGENTS PARTY HERETO (each, a “Purchaser Agent”), THE FINANCIAL INSTITUTIONS FROM TIME TO TIME PARTIES HERETO AS LC PARTICIPANTS (each together with their successors and permitted assigns in such capacity, an “LC Participant”), and PNC BANK, NATIONAL ASSOCIATION, a national banking association (“PNC”), as Purchaser Agent for PNC, as a Conduit Purchaser, as administrator for the Conduit Purchasers (in such capacity, together with its successors and assigns in such capacity, the “Administrator”) and as issuer of Letters of Credit (in such capacity, together with its successors and assigns in such capacity, the “LC Bank”) and each of the other members of each Purchaser Group party hereto or that become parties hereto by executing an Assumption Agreement or a Transfer Supplement.

(b)Section 1.5 of the Agreement is hereby amended by replacing the term “Market Street” where it appears therein with the term “PNC”.

(c)Section 1.7(b) of the Agreement is hereby amended by replacing the term “Euro-Rate” where it appears therein with the phrase “Euro-Rate or LMIR”.

(d)Section 1.7(e) of the Agreement is hereby amended by replacing the phrase “, Market Street or any of their Affiliates” where it appears therein with the phrase “or any of its Affiliates”.

(e)Section 1.8(a)(ii)(B) of the Agreement is hereby amended by replacing the term “Euro-Rate” where it appears therein with the phrase “Euro-Rate or LMIR”.

(f)Section 1.8(b) of the Agreement is hereby amended by replacing the term “Euro-Rate” where it appears therein with the phrase “Euro-Rate or LMIR”.

(g)Section 1.9 of the Agreement is hereby replaced in its entirety with the following:

Section 1.9 Inability to Determine Euro-Rate or LMIR.

(a)    If the Administrator determines before the first day of any Settlement Period (or solely with respect to LMIR, on any day) (which determination shall be final and conclusive) that, by reason of circumstances affecting the interbank eurodollar market generally, (i) deposits in dollars (in the relevant amounts for such Settlement Period) are not being offered to banks in the interbank eurodollar market for such Settlement Period, (ii) adequate means do not exist for ascertaining the Euro-Rate or LMIR for such Settlement Period (or portion thereof) or (iii) the Euro-Rate or LMIR does not accurately reflect the cost to any Purchaser (as determined by such Purchaser) of maintaining any Portion of Capital during such Settlement Period (or portion thereof), then the Administrator shall give notice thereof to the Seller. Thereafter, until the Administrator notifies the Seller that the circumstances giving rise to such suspension no longer exist, (i) no Portion of Capital shall be funded at the Alternate Rate determined by reference to the Euro-Rate or LMIR and (ii) the Discount for any outstanding Portions of Capital then funded at the Alternate Rate determined by reference to the Euro-Rate or LMIR shall, on the last day of the then current Settlement Period (or solely with respect to LMIR, immediately), be converted to the Alternate Rate determined by reference to the Base Rate.

(b)    If, on or before the first day of any Settlement Period (or solely with respect to LMIR, on any day), the Administrator shall have been notified by any Affected Person that such Affected Person has determined (which determination shall be final and conclusive) that any enactment, promulgation or adoption of or any change in any applicable law, rule or regulation, or any change in the interpretation or administration thereof by a governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by such Affected Person with any guideline, request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency shall make it unlawful or impossible for such Affected Person to fund or maintain any Portion of Capital at the Alternate Rate and based upon the Euro-Rate or LMIR, the Administrator shall notify the Seller thereof. Upon receipt of such notice, until the Administrator notifies the Seller that the circumstances giving rise to such determination no longer apply, (i) no Portion of Capital shall be funded at the Alternate Rate determined by reference to the Euro-Rate or LMIR and (ii) the Discount for any outstanding Portions of Capital then funded at the Alternate Rate determined by reference to the Euro-Rate or LMIR shall be converted to the Alternate Rate determined by reference to the Base Rate either (A) on the last day of the then current Settlement Period (or solely with respect to LMIR, immediately) if such Affected Person may lawfully continue to maintain such Portion of Capital at the Alternate Rate determined by reference to the Euro-Rate or LMIR to such day, or (B) immediately, if such Affected Person may not lawfully continue to maintain such Portion of Capital at the Alternate Rate determined by reference to the Euro-Rate or LMIR to such day.

(h)The notice information for PNC in its capacities as Administrator under the Agreement is hereby replaced in its entirety with the following:

Address:    PNC Bank, National Association

Three PNC Plaza

225 Fifth Avenue

Pittsburgh, PA 15222-2707

Attention:    Robyn Reeher

Telephone:    (412) 768-3090

Facsimile:    (412) 762-9184

(i)The signature block as well as the notice information thereunder for Market Street set forth on signature page S-6 of the Agreement are hereby deleted in their entirety.

(j)The following new defined terms and definitions thereof are hereby added to Exhibit I to the Agreement in appropriate alphabetic order:

“BNS Base Rate” means, for any day, a fluctuating interest rate per annum as shall be in effect from time to time, which rate shall be at all times equal to the higher of:

(a)    the rate of interest in effect for such day as publicly announced from time to time by The Bank of Nova Scotia as its “reference rate.” Such “reference rate” is set by The Bank of Nova Scotia based upon various factors, including The Bank of Nova Scotia’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above or below such announced rate, and

(b)    0.50% per annum above the latest Federal Funds Rate.

“LMIR” means for any day during any Settlement Period, the one-month Eurodollar rate for U.S. dollar deposits as reported on the Reuters Screen LIBOR01 Page or any other page that may replace such page from time to time for the purpose of displaying offered rates of leading banks for London interbank deposits in United States dollars, as of 11:00 a.m. (London time) on such day, or if such day is not a Business Day, then the immediately preceding Business Day (or if not so reported, then as determined by the Administrator from another recognized source for interbank quotation), in each case, changing when and as such rate changes.

“PNC Base Rate” means, for any day, a fluctuating interest rate per annum as shall be in effect from time to time, which rate shall be at all times equal to the higher of:

(a)    the rate of interest in effect for such day as publicly announced from time to time by PNC in Pittsburgh, Pennsylvania as its “prime rate.” Such “prime rate” is set by PNC based upon various factors, including PNC’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above or below such announced rate, and

(b)    0.50% per annum above the latest Federal Funds Rate.

“Scheduled Commitment Termination Date” means March 28, 2014.

(a)The definition of “Alternate Rate” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Alternate Rate” for any Settlement Period for any Portion of Capital of the Purchased Interest means an interest rate per annum equal to: (i) solely with respect to PNC, as a Purchaser, (a) the daily average LMIR for such Settlement Period or (b) if LMIR is unavailable as described in Section 1.9, the Base Rate for such Settlement Period or (ii) with respect to any Person other than PNC, (a) 1.75% per annum above the Euro-Rate for such Settlement Period; provided, however, that if (x) it shall become unlawful for any Purchaser or Program Support Provider to obtain funds in the London interbank eurodollar market in order to make, fund or maintain any Purchased Interest, or if such funds shall not be reasonably available to any Purchaser or Program Support Provider, or (y) there shall not be at least two Business Days prior to the commencement of an applicable Settlement Period to determine a Euro-Rate in accordance with its terms, then the “Alternate Rate” shall be equal to the Base Rate in effect for each day during the remainder of such Settlement Period or (b) if requested by the Seller the Base Rate for such Settlement Period; provided, however, that the “Alternate Rate” for any day while a Termination Event exists shall be an interest rate equal to 2.00% per annum above the Base Rate in effect on such day.

(b)The definition of “Base Rate” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Base Rate” means, for any day, (i) in the case of PNC, the PNC Base Rate, (ii) in the case of Liberty Street Funding LLC or The Bank of Nova Scotia, the BNS Base Rate and (iii) in the case of each other Purchaser, the rate set forth as the Base Rate for such Purchaser in the related Fee Letter.

(c)The definition of “Business Day” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Business Day” means any day (other than a Saturday or Sunday) on which: (a) banks are not authorized or required to close in New York City, New York or Pittsburgh, Pennsylvania and (b) if this definition of “Business Day” is utilized in connection with the Euro-Rate or LMIR, dealings are carried out in the London interbank market.

(d)The definition of “CP Rate” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“CP Rate” for any Settlement Period for any Portion of Capital means (i) in the case of Liberty Street Funding LLC, a rate calculated by the Purchaser Agent for Liberty Street Funding LLC equal to: (a) the rate (or if more than one rate, the weighted average of the rates) at which Notes of Liberty Street Funding LLC on each day during such period have been outstanding; provided, that if such rate(s) is a discount rate(s), then the CP Rate shall be the rate (or if more than one rate, the weighted average of the rates) resulting from converting such discount rate(s) to an interest-bearing equivalent rate plus (b) the commissions and charges charged by such placement agent or commercial paper dealer with respect to such Notes, expressed as a percentage of the face amount of such Notes and converted to an interest-bearing equivalent rate per annum, and (ii) in the case of each other Conduit Purchaser, the rate set forth as the CP Rate for such Conduit Purchaser in the related Fee Letter. Notwithstanding the foregoing, the “CP Rate” for any day while a Termination Event exists shall be an interest rate equal to 2% above the Base Rate in effect on such day.

(e)The definition of “ Facility Termination Date” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Facility Termination Date” means the earliest to occur of: (a) March 30, 2017, (b) the date determined pursuant to Section 2.2 of the Agreement, (c) the date the Purchase Limit reduces to zero pursuant to Section 1.1(b) of the Agreement, (d) the Scheduled Commitment Termination Date, and (e) any Conduit Purchaser or any Purchaser Agent shall fail to cause the amendment or modification of any Transaction Document or related opinion as required by Moody’s or Standard and Poor’s, and such failure shall continue for 30 days after such amendment is initially requested.

(f)The defined term “Market Street” as well as the definition thereof set forth in Exhibit I to the Agreement are hereby deleted in their entirety.

(g)The definition of “Notes” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Notes” means short-term promissory notes issued, or to be issued, by each Conduit Purchaser to fund its investments in accounts receivable or other financial assets; provided, however, that PNC, as a Conduit Purchaser, shall be deemed not to have any Notes for purposes of this Agreement or any other Transaction Document.

(h)The definition of “Purchaser Group” set forth in Exhibit I to the Agreement is replaced in its entirety with the following:

“Purchaser Group” means, (i) for each Conduit Purchaser, such Conduit Purchaser, its related Purchaser Agent and its related LC Participant and (ii) for PNC, PNC, as a Conduit Purchaser, a Purchaser Agent, an LC Participant and the LC Bank.

(i)The definition “Year” set forth in the definition of “Discount” set forth in Exhibit I to the Agreement is hereby amended by replacing the term “Euro-Rate” where it appears therein with the phrase “Euro-Rate or LMIR”.

(j)Annex B to the Agreement is hereby replaced in its entirety with Exhibit A attached hereto.

(k)Annex C to the Agreement is hereby replaced in its entirety with Exhibit B attached hereto.

SECTION 5.Representations and Warranties. Each of the Seller, CONSOL Energy and the Servicer hereby represents and warrants to the Administrator, the Purchaser Agents, the Purchasers and the Assignee as follows:

(a)Representations and Warranties. The representations and warranties made by it in the Transaction Documents are true and correct as of the date hereof (unless stated to relate solely to an earlier date, in which case such representations or warranties were true and correct as of such earlier date).

(b)Enforceability. The execution and delivery by such Person of this Amendment, and the performance of each of its obligations under this Amendment and the Agreement, as amended hereby, are within each of its corporate powers and have been duly authorized by all necessary corporate action on its part. This Amendment and the Agreement, as amended hereby, are such Person’s valid and legally binding obligations, enforceable in accordance with its terms.

(c)No Default. Both before and immediately after giving effect to this Amendment and the transactions contemplated hereby, no Termination Event or Unmatured Termination Event exists or shall exist.

SECTION 6.Effect of Amendment. All provisions of the Agreement, as expressly amended and modified by this Amendment, shall remain in full force and effect. After this Amendment becomes effective, all references in the Agreement (or in any other Transaction Document) to “this Agreement”, “hereof”, “herein” or words of similar effect referring to the Agreement shall be deemed to be references to the Agreement as amended by this Amendment. This Amendment shall not be deemed, either expressly or impliedly, to waive, amend or supplement any provision of the Agreement other than as set forth herein.

SECTION 7.Effectiveness. This Amendment shall become effective as of the date (such date, the “Effective Date”) upon which each of the following conditions precedent have been satisfied: (a) receipt by the Administrator of each of the following, in each case, in form and substance reasonably satisfactory to the Administrator: (i) counterparts of this Amendment (whether by facsimile or otherwise), executed by each of the parties hereto, (ii) counterparts of the Fee Letter (whether by facsimile or otherwise), executed by each of the parties thereto and (iii) such other approvals, opinions or documents as the Administrator or the Issuer may reasonably request and (b) receipt by the Assignor of the Payoff Amount in its entirety in accordance with Section 2 of this Amendment.

SECTION 8.Further Assurances. Each of the Seller and the Servicer hereby agrees to do all such things and execute all such documents and instruments, at the Seller’s sole expense, as the Assignee may reasonably consider necessary or desirable to give full effect to the assignment and assumption set forth in Section 2 of this Amendment.

SECTION 9.No Proceedings. Each of the parties hereto hereby covenants and agrees that it will not institute against, or join any other Person in instituting against, Market Street any bankruptcy, reorganization, arrangement, insolvency or liquidation proceeding, or other proceeding under any federal or state bankruptcy or similar law, for one year and one day after the latest maturing Note issued by Market Street is paid in full. The provisions of this Section 9 shall survive any termination of the Agreement.

SECTION 10.Counterparts. This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute but one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by facsimile or electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

SECTION 11.Governing Law. This Amendment shall be governed by, and construed in accordance with, the internal laws of the State of New York.

SECTION 12.Severability. If any one or more of the agreements, provisions or terms of this Amendment shall for any reason whatsoever be held invalid or unenforceable, then such agreements, provisions or terms shall be deemed severable from the remaining agreements, provisions and terms of this Amendment and shall in no way affect the validity or enforceability of the provisions of this Amendment or the Agreement.

SECTION 13.Section Headings. The various headings of this Amendment are included for convenience only and shall not affect the meaning or interpretation of this Amendment, the Agreement or any provision hereof or thereof.

[SIGNATURES BEGIN ON NEXT PAGE]

IN WITNESS WHEREOF, the parties have executed this Amendment as of the date first written above.

CNX FUNDING CORPORATION,

as Seller

By: /s/ Christopher C. JonesName: Christopher C. Jones
Title: Vice President and Secretary

CONSOL ENERGY INC.,
as initial Servicer

By: /s/ John M. ReillyName: John M. Reilly
Title: Vice President and Treasurer

CNX MARINE TERMINALS INC.,

CONSOL ENERGY SALES COMPANY,

CONSOL OF KENTUCKY INC.,

CONSOL PENNSYLVANIA COAL COMPANY, LLC,

FOLA COAL COMPANY, L.L.C.,

LITTLE EAGLE COAL COMPANY, L.L.C.,

MON RIVER TOWING, INC., and

TERRY EAGLE COAL COMPANY, L.L.C.,

each as a Sub-Servicer

By: /s/ John M. Reilly    

Name:    John M. Reilly

Title:    Treasurer

CONSOLIDATION COAL COMPANY,

EIGHTY-FOUR MINING COMPANY,

ISLAND CREEK COAL COMPANY,

KEYSTONE COAL MINING CORPORATION,

MCELROY COAL COMPANY, and

TWIN RIVERS TOWING COMPANY,

each as a Sub-Servicer

By: /s/ Steven T. Aspinall    

Name:    Steven T. Aspinall

Title:    Treasurer

MARKET STREET FUNDING LLC,
as a Conduit Purchaser and as Assignor

By: /s/ Doris J. Hearn                    Name:    Doris J. Hearn
Title:     Vice President

PNC BANK, NATIONAL ASSOCIATION,
as Administrator, as a Purchaser Agent
and as Assignee

By: /s/ Robyn A. Reeher                Name:    Robyn A. Reeher
Title:     Vice President

PNC BANK, NATIONAL ASSOCIATION,
as the LC Bank and as an LC Participant

By: /s/ Robyn A. Reeher                Name:    Robyn A. Reeher
Title:     Vice President

LIBERTY STREET FUNDING LLC,
as a Conduit Purchaser

By: /s/ Jill A. Russo                    Name:    Jill A. Russo
Title:    Vice President

THE BANK OF NOVA SCOTIA,
as Purchaser Agent for
Liberty Street Funding LLC

By: /s/ Thane Rattew                    Name:    Thane Rattew
Title:    Managing Director

THE BANK OF NOVA SCOTIA,
as an LC Participant

By: /s/ Thane Rattew                    Name:    Thane Rattew
Title:    Managing Director

SCHEDULE I

ASSIGNMENTS AND PAYMENT AMOUNTS

Section 1.
Capital Payment:	$695,173.00
Section 2.
Discount:	$0
Fees:	$0
Other Amounts:	$0
CP Costs and Other Costs:	$0

SCHEDULE II

WIRING INSTRUCTIONS

Wiring instructions with respect to amounts payable to the Assignor:

Bank Name:	PNC Bank, National Association
ABA #:	43000096
Account #:	1002422076
Account Name:	Market Street Funding LLC
Reference:	CNX Funding Corporation

EXHIBIT A

ANNEX B

to Receivables Purchase Agreement

FORM OF PURCHASE NOTICE

______________, [200_]

PNC Bank, National Association, as Administrator and a Purchaser Agent

Three PNC Plaza

225 Fifth Avenue

Pittsburgh, PA 15222-2707

The Bank of Nova Scotia, as a Purchaser Agent

One Liberty Plaza

New York, NY 10006

Ladies and Gentlemen:

Reference is hereby made to the Amended and Restated Receivables Purchase Agreement, dated as of April 30, 2007 (as heretofore amended, supplemented or otherwise modified, the “Receivables Purchase Agreement”), among CNX Funding Corporation, as Seller, CONSOL Energy Inc., as Servicer, CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals, as the Sub-Servicers, the Conduit Purchasers party thereto, the Purchaser Agents party thereto, PNC Bank, National Association, as Administrator and as LC Bank and the LC Participants from time to time party thereto. Capitalized terms used in this Purchase Notice and not otherwise defined herein shall have the meanings assigned thereto in the Receivables Purchase Agreement.

This letter constitutes a Purchase Notice pursuant to Section 1.2(a) of the Receivables Purchase Agreement. Seller desires to sell an undivided variable interest in a pool of receivables on ____________, [200_], for a purchase price of $______________ ($______________ of which represents the Capital funded by the Purchaser Group for which PNC is a member and $______________ of which represents the Capital funded by the Purchaser Group for which Liberty Street Funding LLC is a member). Subsequent to this purchase, the aggregate outstanding Capital will be $______________. Each Purchaser Group’s Share of such purchase and resulting aggregate Capital and LC Participation Amount is set forth on a schedule attached hereto.

Seller hereby represents and warrants as of the date hereof, and as of the date of purchase, as follows:

(i)the representations and warranties contained in Exhibit III of the Receivables Purchase Agreement are correct on and as of such dates as though made on and as of such dates and shall be deemed to have been made on such dates;

(ii)no Termination Event or Unmatured Termination Event has occurred and is continuing, or would result from such purchase;

(iii)after giving effect to the purchase proposed hereby, the Purchased Interest will not exceed 100% and the Capital plus the LC Participation Amount will not exceed the Purchase Limit; and

(iv)the Facility Termination Date shall not have occurred.

IN WITNESS WHEREOF, the undersigned has caused this Purchase Notice to be executed by its duly authorized officer as of the date first above written.

CNX FUNDING CORPORATION

By:

Name:

Title:__________________________

EXHIBIT B

ANNEX C

to Receivables Purchase Agreement

FORM OF PAYDOWN NOTICE

_____________, _____

PNC Bank, National Association, as Administrator and a Purchaser Agent

Three PNC Plaza

225 Fifth Avenue

Pittsburgh, PA 15222-2707

The Bank of Nova Scotia, as a Purchaser Agent

One Liberty Plaza

New York, NY 10006

Ladies and Gentlemen:

Reference is hereby made to the Amended and Restated Receivables Purchase Agreement, dated as of April 30, 2007 (as heretofore amended, supplemented or otherwise modified, the “Receivables Purchase Agreement”), among CNX Funding Corporation, as Seller, CONSOL Energy Inc., as Servicer, CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals, as the Sub-Servicers, the Conduit Purchasers party thereto, the Purchaser Agents party thereto, PNC Bank, National Association, as Administrator and as the LC Bank and the LC Participants from time to time party thereto. Capitalized terms used in this paydown notice and not otherwise defined herein shall have the meanings assigned thereto in the Receivables Purchase Agreement.

This letter constitutes a paydown notice pursuant to Section 1.4(f)(i) of the Receivables Purchase Agreement. The Seller desires to reduce the Capital on _____________, _____ by the application of $_______________ ($_______________ of which shall be applied to the Capital funded by the Purchaser Group for which PNC is a member and $_______________ of which shall be applied to the Capital funded by the Purchaser Group for which Liberty Street Funding LLC is a member) in cash to pay Capital and Discount to accrue (until such cash can be used to pay commercial paper notes) with respect to such Capital, together with all costs related to such reduction of Capital. Subsequent to this paydown, the aggregate Capital will be $_______________. Each Purchaser Group’s Share of such reduction and resulting aggregate Capital is set forth on a schedule attached hereto.

IN WITNESS WHEREOF, the undersigned has caused this paydown notice to be executed by its duly authorized officer as of the date first above written

CNX FUNDING CORPORATION
By:Name:
Title:

707425525 09097997

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, J. Brett Harvey, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 1, 2013
/s/ J. Brett Harvey
J. Brett Harvey
Chairman of the Board and Chief Executive Officer
(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, David M. Khani, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 1, 2013
/s/ David M. Khani
David M. Khani
Chief Financial Officer and Executive Vice President (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION

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

18 U.S.C. Section 1350

I, J. Brett Harvey, President and Chief Executive Officer (principal executive officer) of CONSOL Energy Inc. (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended September 30, 2013, of the Registrant (the “Report”):

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

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

Date:	November 1, 2013
/s/ J. Brett Harvey
J. Brett Harvey
Chairman of the Board and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

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

18 U.S.C. Section 1350

I, David M. Khani, Chief Financial Officer (principal financial officer) of CONSOL Energy Inc. (the “Registrant”), certify that to my knowledge, based upon a review of the Quarterly Report on Form 10-Q for the period ended September 30, 2013, of the Registrant (the “Report”):

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

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

Date:	November 1, 2013
/s/ David M. Khani
David M. Khani
Chief Financial Officer and Executive Vice President

EX-95

Mine Safety and Health Administration Safety Data

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

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

The table below sets forth for the three months ended September 30, 2013 for each coal mine of CONSOL Energy and its subsidiaries, the total number of:  (i) violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) orders issued under section 104(b) of the Mine Act; (iii) citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act; (iv) flagrant violations under section 110(b)(2) of the Mine Act; (v) imminent danger orders issued under section 107(a) of the Mine Act; (vi) proposed assessments from MHSA (regardless of whether CONSOL Energy has challenged or appealed the assessment); (vii) mining-related fatalities; (viii) notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under section 104(e) of the Mine Act; (ix) notices from MSHA regarding the potential to have a pattern of violations as referenced in (viii) above; and (x) pending legal actions before the Federal Mine Safety and Health Review Commission (as of September 30, 2013) involving such coal or other mine, as well as the aggregate number of legal actions instituted and the aggregate number of legal actions resolved during the reporting period.

1

										Received
										Notice
									Received	of	Legal
								Total	Notice of	Potential	Actions
				Section			Total Dollar	Number	Pattern of	to have	Pending	Legal	Legal
		Section		104(d)			Value of	of	Violations	Pattern	as of	Actions	Actions
Mine or Operating		104	Section	Citations	Section	Section	MSHA	Mining	Under	Under	Last	Initiated	Resolved
Name/MSHA		S&S	104(b)	and	110(b)(2)	107(a)	Assessments	Related	Section	Section	Day of	During	During
Identification Number		Citations	Orders	Orders	Violations	Orders	Proposed	Fatalities	104(e)	104(e)	Period (1)	Period	Period
Active Operations
Alma No. 1 Mine	46-09277	3	—	—	—	—	2,733	—	No	No	—	—	—
Bailey	36-07230	19	—	—	—	—	25,068	—	No	No	11	4	1
Blacksville 2	46-01968	45	—	—	—	—	101,210	—	No	No	22	4	7
Buchanan	44-04856	12	—	—	—	—	50,439	—	No	No	34	5	—
Central Repair Shop	46-03240	1	—	—	—	—	300	—	No	No	—	—	—
Enlow Fork	36-07416	25	—	—	—	—	61,042	—	No	No	7	5	3
Ireland Dock Loadout	46-01438	1	—	—	—	—	100	—	No	No	5	—	—
Keystone Cleaning Plant	36-08540		—	—	—	—	100	—	No	No	—	—	—
Loveridge	46-01433	64	—	2	—	—	287,611	—	No	No	24	6	6
McElroy	46-01437	66	—	5	—	—	161,412	—	No	No	30	7	7
Miller Creek PP #1	46-05890	6	—	—	—	—	—	—	No	No	—	—	1
Robinson Run	46-01318	58	—	4	—	—	78,524	—	No	No	34	4	3
Shoemaker	46-01436	30	—	—	—	—	44,609	—	No	No	23	3	4
Twin Branch Surface	46-09075	1	—	—	—	—	663	—	No	No	—	—	—
Inactive Operations
Amonate Plant	46-05449	—	—	—	—	—	—	—	No	No	—	—	—
Big Branch #1Belt/Spruce Creek	46-09177	—	—	—	—	—	—	—	No	No	—	—	—
Big Fork	44-06859	—	—	—	—	—	—	—	No	No	—	—	—
Bronzite II (MT-41)	46-09307	—	—	—	—	—	—	—	No	No	—	—	—
Bronzite III (Jacobs)	46-05978	—	—	—	—	—	833	—	No	No	1	—	—
Elk Creek Prep Plant (Sold)	46-02444	—	—	—	—	—	—	—	No	No	—	—	—
Emery	42-00079	—	—	—	—	—	—	—	No	No	—	—	1
Fola Surface	46-08377	—	—	—	—	—	—	—	No	No	1	—	—
Ike Fork 5 Block	46-09420	—	—	—	—	—	—	—	No	No	1	—	—
Impoundment 14-N	36-08094	—	—	—	—	—	—	—	No	No	—	—	—
Jones Fork Prep Plant (Sold)	15-17021	—	—	—	—	—	—	—	No	No	—	—	—
Laurel Fork	46-09084	—	—	—	—	—	100	—	No	No	—	—	—

2

Lick Branch	46-08676	—	—	—	—	—	—	—	No	No	—	—	—
Little Eagle Mine #1	46-08560	—	—	—	—	—	—	—	No	No	—	—	—
Meigs #31 Mine	33-01172	—	—	—	—	—	—	—	No	No	—	—	—
Miles Branch	44-03932	—	—	—	—	—	—	—	No	No	—	—	—
Mine 84	36-00958	—	—	—	—	—	—	—	No	No	—	—	—
Minway Surface	46-06089	—	—	—	—	—	—	—	No	No	—	—	—
MT-34 UG	46-09424	—	—	—	—	—	—	—	No	No	—	—	—
Muskingum	33-00989	—	—	—	—	—	—	—	No	No	—	—	—
Peach Orchard Prep Plant	46-08376	—	—	—	—	—	—	—	No	No	—	—	—
Powellton/Bridge Fork	46-08889	—	—	—	—	—	—	—	No	No	—	—	—
Reclamation #061	33-00962	—	—	—	—	—	—	—	No	No	—	—	—
Rend Lake	11-00601	—	—	—	—	—	—	—	No	No	—	—	—
Robena Prep	36-04175	—	—	—	—	—	—	—	No	No	—	—	—
Rock Lick	46-09171	—	—	—	—	—	—	—	No	No	—	—	1
Squire Jim #2	46-09211	—	—	—	—	—	—	—	No	No	—	—	—
Terry Eagle PP #1	46-02295	—	—	—	—	—	—	—	No	No	—	—	—
Wiley (MT-11)	46-09138	—	—	—	—	—	—	—	No	No	—	—	—
Wiley Area 80	15-18477	—	—	—	—	—	—	—	No	No	—	—	—
Wiley Creek (MT-13/500)	46-09185	—	—	—	—	—	100	—	No	No	—	—	2
Wiley Surface(MT34/Peg Fork)	46-09035	—	—	—	—	—	100	—	No	No	—	—	1
Winoc Prep Plant	46-08172	—	—	—	—	—	—	—	No	No	—	—	—
		331	—	11	—	—	814,944	—			193	38	37

(1) See table below for additional detail regarding Legal Actions Pending as of September 30, 2013.  With respect to Contests of Proposed Penalties, we have included the number of dockets (as opposed to citations) when counting the number of Legal Actions Pending as of September 30, 2013.

3

Mine or Operating Name/MSHA Identification Number		Contests of Citations, Orders (as of 9.30.13) (a)	Contests of Proposed Penalties (as of 9.30.13) (b)		Complaints for Compensation (as of 9.30.13) (c)	Complaints of Discharge, Discrimination or Interference (as of 9.30.13) (d)	Applications for Temporary Relief (as of 9.30.13) (e)	Appeals of Judges' Decisions or Order (as of 9.30.13) (f)
			Dockets	Citations
Active Operations
Alma No. 1 Mine	46-09277	—	—	—	—	—	—	—
Bailey	36-07230	—	10	31	—	1	—	—
Blacksville 2	46-01968	—	22	268	—	—	—	—
Buchanan	44-04856	—	32	297	—	2	—	—
Central Repair Shop	46-03240	—	—	—	—	—	—	—
Enlow Fork	36-07416	—	7	23	—	—	—	—
Ireland Dock Loadout	46-01438	—	5	6	—	—	—	—
Keystone Cleaning Plant	36-08540	—	—	—	—	—	—	—
Loveridge	46-01433	—	23	150	—	1	—	—
McElroy	46-01437	—	29	528	—	1	—	—
Miller Creek PP #1	46-05890	—	—	—	—	—	—	—
Robinson Run	46-01318	—	33	384	—	—	—	1
Shoemaker	46-01436	—	22	235	—	1	—	—
Twin Branch Surface	46-09075	—	—	—	—	—	—	—
Inactive Operations
Amonate Plant	46-05449	—	—	—	—	—	—	—
Big Branch #1Belt/Spruce Creek	46-09177	—	—	—	—	—	—	—
Big Fork	44-06859	—	—	—	—	—	—	—
Bronzite II (MT‑41)	46-09307	—	1	1	—	—	—	—
Bronzite III (Jacobs)	46-05978	—	—	—	—	—	—	—
Elk Creek Prep Plant (Sold)	46-02444	—	—	—	—	—	—	—
Emery	42-00079	—	—	—	—	—	—	—
Fola Surface	46-08377	—	1	3	—	—	—	—
Ike Fork 5 Block	46-09420	—	1	1	—	—	—	—
Impoundment 14‑N	36-08094	—	—	—	—	—	—	—
Jones Fork Prep Plant(Sold)	15-17021	—	—	—	—	—	—	—

4

Laurel Fork	46-09084	—	—	—	—	—	—	—
Lick Branch	46-08676	—	—	—	—	—	—	—
Little Eagle Mine #1	46-08560	—	—	—	—	—	—	—
Meigs #31 Mine	33-01172	—	—	—	—	—	—	—
Miles Branch	44-03932	—	—	—	—	—	—	—
Mine 84	36-00958	—	—	—	—	—	—	—
Minway Surface	46-06089	—	—	—	—	—	—	—
MT-34 UG	46-09424	—	—	—	—	—	—	—
Muskingum	33-00989	—	—	—	—	—	—	—
Peach Orchard Prep Plant	46-08376	—	—	—	—	—	—	—
Powellton/Bridge Fork	46-08889	—	—	—	—	—	—	—
Reclamation #061	33-00962	—	—	—	—	—	—	—
Rend Lake	11-00601	—	—	—	—	—	—	—
Robena Prep	36-04175	—	—	—	—	—	—	—
Rock Lick	46-09171	—	—	—	—	—	—	—
Squire Jim #2	46-09211	—	—	—	—	—	—	—
Terry Eagle PP #1	46-02295	—	—	—	—	—	—	—
Wiley (MT‑11)	46-09138	—	—	—	—	—	—	—
Wiley Area 80	15-18477	—	—	—	—	—	—	—
Wiley Creek (MT‑13/500)	46-09185	—	—	—	—	—	—	—
Wiley Surface(MT34/Peg Fork)	46-09035	—	—	—	—	—	—	—
Winoc Prep Plant	46-08172	—	—	—	—	—	—	—
		—	186	1,927	—	6	—	1

5

(a) Represents (if any) contests of citations and orders, which typically are filed prior to an operator's receipt of a proposed penalty assessment from MSHA or relate to orders for which penalties are not assessed (such as imminent danger orders under Section 107 of the Mine Act). This category includes: (i) contests of citations or orders issued under section 104 of the Mine Act, (ii) contests of imminent danger withdrawal orders under section 107 of the Mine Act, and (iii) Emergency response plan dispute proceedings (as required under the Mine Improvement and New Emergency Response Act of 2006, Pub. L. No. 109-236, 120 Stat. 493).

(b) Represents (if any) contests of proposed penalties, which are administrative proceedings before the Federal Mine Safety and Health Review Commission (“FMSHRC”) challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order. This column includes four actions involving civil penalties against agents of the operator that have been contested.

(c) Represents (if any) complaints for compensation, which are cases under section 111 of the Mine Act that may be filed with the FMSHRC by miners idled by a closure order issued by MSHA who are entitled to compensation.

(d) Represents (if any) complaints of discharge, discrimination or interference under section 105 of the Mine Act, which cover: (i) discrimination proceedings involving a miner's allegation that he or she has suffered adverse employment action because he or she engaged in activity protected under the Mine Act, such as making a safety complaint, and (ii) temporary reinstatement proceedings involving cases in which a miner has filed a complaint with MSHA stating that he or she has suffered such discrimination and has lost his or her position. Complaints of Discharge, Discrimination, or Interference are also included in Contests of Proposed Penalties, Column B.

(e) Represents (if any) applications for temporary relief, which are applications under section 105(b)(2) of the Mine Act for temporary relief from any modification or termination of any order or from any order issued under section 104 of the Mine Act (other than citations issued under section 104(a) or (f) of the Mine Act).

(f) Represents (if any) appeals of judges' decisions or orders to the FMSHRC, including petitions for discretionary review and review by the FMSHRC on its own motion.

6

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Short-Term Notes Payable

9 Months Ended

Sep. 30, 2013

Short-term Debt, Other Disclosures [Abstract]

Short-Term Notes Payable:

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 (Adjusted 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 3.96 to 1.00 at September 30, 2013. The facility includes a maximum leverage ratio covenant of no more than 4.50 to 1.00, measured quarterly. The leverage ratio was 3.21 to 1.00 at September 30, 2013. 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 0.11 to 1.00 at September 30, 2013. 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 September 30, 2013, the $1,500,000 facility had no borrowings outstanding and $104,137 of letters of credit outstanding, leaving $1,395,863 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the $1,500,000 facility had no borrowings outstanding and $100,292 of letters of credit outstanding, leaving $1,399,708 of capacity available for borrowings and the issuance of letters of credit.

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 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 CONE Gathering, LLC (CONE) 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 0.75 to 1.00 at September 30, 2013. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 28.55 to 1.00 at September 30, 2013. At September 30, 2013, the $1,000,000 facility had $47,000 borrowings outstanding and $70,051 of letters of credit outstanding, leaving $882,949 of capacity available for borrowings and the issuance of letters of credit. At December 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 average interest rate for the three months and nine months ended September 30, 2013 was 1.80% and 1.76%, respectively. Accrued interest of $5 and $29 was included in Other Accrued Liabilities in the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012, respectively.

CONSOL Energy entered into an interim funding arrangement for longwall shields. At December 31, 2012, CONSOL

Energy had a note payable of $25,073 related to this funding arrangement. The interim funding arrangement bore a weighted average interest rate of 2.46% as of December 31, 2012. There were no interim funding agreements outstanding at September 30, 2013.

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Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Coal and other plant and equipment	$ 6,207,105	$ 6,030,620
Drilling Cost	1,830,666	1,550,297
Proven gas properties	1,601,106	1,596,838
Coal properties and surface lands	1,449,526	1,346,151
Unproven gas properties	1,383,921	1,266,017
Gas gathering equipment	1,046,495	1,006,882
Airshafts	746,134	706,388
Mine development	608,630	537,939
Leased coal lands	529,409	529,758
Gas wells and related equipment	623,176	492,367
Coal advance mining royalties	397,015	391,501
Other gas assets	125,635	82,217
Gas advance royalties	22,286	8,229
Total property plant and equipment	16,571,104	15,545,204
Less Accumulated depreciation, depletion and amortization	5,940,247	5,354,237
Total Property, Plant and Equipment-Net	$ 10,630,857	$ 10,190,967

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Consolidated Statements of Comprehensive Income (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Comprehensive Income (Loss), Tax	$ 14,025	$ 29,683	$ 36,551	$ 97,760
Adjustment For Actuarially Determined Liabilities [Member]
Other Comprehensive Income (Loss), Tax	(15,422)	(4,775)	(70,161)	(45,242)
Cash Flow Hedging [Member]
Other Comprehensive Income (Loss), Tax	$ (8,536)	$ 4,161	$ (26,036)	$ (51,716)

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2013

ACQUISITIONS AND DISPOSITIONS: [Abstract]

Acquisitions and Dispositions:

ACQUISITIONS AND DISPOSITIONS:

In September 2013, CONSOL Energy completed the sale of 1.5 MM tons of reserves of Pittsburgh 8 Coal in Belmont County, Ohio. The sale of this coal was structured as a $2,300 payment upfront and then a 3% overriding royalty paid as the coal is being mined. A gain of $2,300 was included in Other Income in the Consolidated Statement of Income.

In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24,764 of which $12,263 was restricted, pending release by the Canadian Revenue Authority upon review of the tax consequences of the transaction. A gain of $15,260 was included in Other Income in the Consolidated Statement of Income.

In June 2013, CONSOL Energy completed the sale of Potomac coal reserves in Grant and Tucker Counties in West Virginia. Cash proceeds for the sale were $25,000. A gain of $24,663 was included in Other Income in the Consolidated Statement of Income.    

In May 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Robinson Run Mine. Cash proceeds for the sale were $68,337. A loss of $236 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

In April 2013, the Company and the Commonwealth of Pennsylvania (Commonwealth) entered into a Settlement Agreement and Release settling all of the Commonwealth's claims regarding the Ryerson Park Dam (Dam) and the Ryerson Park Lake (Lake).   The Settlement provides in part for the payment to the Commonwealth of $36,000 for use to rebuild the Dam and restore the Lake with $13,728 of the settlement amount credited to lease bonus and royalty payments on the Commonwealth's Marcellus gas interests within the Park, subject to the Company's agreement to extract the gas from surface facilities located outside of the boundaries of the Park.  The Settlement also provides in part for the conveyance by the Company to the Commonwealth of eight surface parcels containing approximately 506 acres of land adjoining the Park after the parcels are no longer needed for the Company's operations and the conveyance by the Commonwealth to the Company of certain coal and mining rights in an area of the Bailey Mine where a mining permit application is currently pending.

In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres.  A majority of these contiguous acres are in the liquids area of the Marcellus Shale play.  CNX Gas Company paid $46,315 as an up-front bonus payment at closing.  Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title.  CNX Gas Company must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company forgoes the bonus. Our joint venture partner, Noble Energy Inc., has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs during the nine months ended September 30, 2013.

In March 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Shoemaker Mine. Cash proceeds for the sale were $63,839. A loss of $279 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

In January 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $71,166. A loss of $358 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accounted for as an operating lease. The lease term is five years.

On December 21, 2012, CONSOL Energy completed the disposition of its non-producing Ram River & Scurry Ram assets in Western Canada which consisted of 36 thousand acres of coal lands. In December 2012, cash proceeds of $51,869, of which $48,294 was restricted, were received related to this transaction. These proceeds were net of $637 in transaction fees. The restrictions on the cash were removed during the three months ended March 31, 2013 and are reflected as a Change in Restricted Cash in the Investing section of the Consolidated Statement of Cash Flows. Additionally, a note receivable was recognized in 2012 related to the two additional cash payments to be received in June 2013 and June 2014. Payment of $25,500 was received in June 2013. A note receivable of $24,500 was included in Accounts and Notes Receivables - Notes Receivables in the Consolidated Balance Sheet at September 30, 2013. The second payment is due June 2014. The gain on the transaction was $89,943 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On June 29, 2012, CONSOL Energy completed the disposition of its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for cash proceeds of $169,500. The assets consisted of CONSOL Energy's 50% interest in Youngs Creek Mining Company LLC, CONSOL Energy's 50% interest in CX Ranch and related properties in and around Sheridan, Wyoming. The gain on the transaction was $150,677 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal.

On April 4, 2012, CONSOL Energy completed the disposition of its non-producing Elk Creek property in southern West Virginia, which consisted of 20 thousand acres of coal lands and surface rights, for proceeds of $26,000. The gain on the transaction was $11,235 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property in Illinois, 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 was included in Other Income in the Consolidated Statements of Income for the year ended December 31, 2012.

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Recent Accounting Pronouncements (Notes)

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

RECENT ACCOUNTING PRONOUNCEMENTS:

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: (a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

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Guarantor Subsidiaries Financial Information Additional Information (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Cash and Cash Equivalents	$ 21,086	$ 21,878	$ 230,958	$ 375,736
Trade	436,388	428,328
Notes Receivable, Related Parties, Current	25,813	318,387
Other Receivables	160,931	131,131
Accounts Receivable - Securitized	44,364	37,846
Inventories	238,348	247,766
Deferred Income Taxes	81,825	148,104
Senior Notes Due April 2017 at 8.00%
Condensed Financial Statements, Captions [Line Items]
Debt Instrument, Face Amount	1,500,000
Debt Instrument, Interest Rate, Stated Percentage	8.00%
Senior notes due April 2020 at 8.25%
Condensed Financial Statements, Captions [Line Items]
Debt Instrument, Face Amount	1,250,000
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Senior notes due March 2021 at 6.375%
Condensed Financial Statements, Captions [Line Items]
Debt Instrument, Face Amount	$ 250,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%

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Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Capital Lease Obligations, Current	$ 8,576	$ 8,941
Debt	3,128,361	3,129,017
Less amounts due in one year	(4,606)	(4,544)
Long-Term Debt	3,123,755	3,124,473
Accrued interest	113,589	63,363
Senior Notes Due April 2017 at 8.00%
Debt Instrument [Line Items]
Debt	1,500,000	1,500,000
Senior notes due April 2020 at 8.25%
Debt Instrument [Line Items]
Debt	1,250,000	1,250,000
Senior notes due March 2021 at 6.375%
Debt Instrument [Line Items]
Debt	250,000	250,000
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%
Debt Instrument [Line Items]
Debt	102,865	102,865
Advance royalty commitments
Debt Instrument [Line Items]
Debt	20,394	20,394
Other long-term notes maturing at various dates through 2031
Debt Instrument [Line Items]
Debt	$ 5,102	$ 5,758

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Long-Term Debt

9 Months Ended

Sep. 30, 2013

Long-term Debt, Other Disclosures [Abstract]

Long-term Debt

LONG-TERM DEBT:

	September 30, 2013		December 31, 2012
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
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.43% weighted average interest rate for September 30, 2013 and December 31, 2012)	20,394		20,394
Other long-term notes maturing at various dates through 2031 (total value of $6,268 and $7,300 less unamortized discount of $1,166 and $1,542 at September 30, 2013 and December 31, 2012, respectively).	5,102		5,758
	3,128,361		3,129,017
Less amounts due in one year *	4,606		4,544
Long-Term Debt	$	3,123,755	$	3,124,473

* Excludes current portion of Capital Lease Obligations of $8,576 and $8,941 at September 30, 2013 and December 31, 2012, respectively.

Accrued interest related to Long-Term Debt of $113,589 and $63,363 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2013 and December 31, 2012, respectively.

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Income Taxes Additional Information (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Deferred Tax Liability Not Recognized [Line Items]
Income Tax Reconciliation, Nondeductible Expense, Depletion	$ 111,104	$ 53,932
Uncertain tax positions	22,770	25,570
Uncertain tax positions that, if recognized, would impact effective tax rate	2,071	3,891
Accrued interest liability relating to uncertain tax positions	5,851	7,095
Interest expense included in accrued interest liability	1,020	1,722
Effective Income Tax Rate Reconciliation, Other Adjustments		$ 5,875

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Commitments and Contingencies Additional Information (Details) (USD $)				9 Months Ended	3 Months Ended				9 Months Ended			12 Months Ended	3 Months Ended			3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Subsidiaries	Sep. 30, 2013 South Carolina Electric Gas Company [Member]	Sep. 30, 2012 South Carolina Electric Gas Company [Member] Counterclaim [Member]	Sep. 30, 2012 South Carolina Electric Gas Company [Member] Award Amount [Member]	Sep. 30, 2012 South Carolina Electric Gas Company [Member] Interest Rate on Amount Awarded [Member]	Sep. 30, 2012 South Carolina Electric Gas Company [Member] Attorney Fees [Member]	Sep. 30, 2013 PCB Soil Removal Action	Sep. 30, 2012 PCB Soil Removal Action	Sep. 30, 2013 American electric corp [Member]	Dec. 31, 2012 American electric corp [Member]	Dec. 31, 2007 Earl Kennedy	Sep. 30, 2013 Cnx Gas Stock Acquisition [Member]	Dec. 31, 2012 Cnx Gas Stock Acquisition [Member]	Sep. 30, 2013 Ratliff [Member]
Commitments and Contingencies Disclosure [Line Items]
Loss Contingency, Range of Possible Loss, Portion Not Accrued	$ 792,000,000
Claims by plaintiff				36000									The complaint, as amended, seeks injunctive relief, including removing CNX Gas Company from the property, and compensatory damages of $20,000.			$4,000 to $8,000
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									65,000,000		5,400,000			19,200
Litigation Settlement, Gross												250,000
Counterclaim by the company					9400	9735	8.75	1232			408
Sale of Stock, Price Per Share															$ 38.25
Loss Contingency, Settlement Agreement, Court														42730
Loss Contingency, Estimate of Possible Loss									12,800,000
Cost of Remediation									1,000
Amount Funded to Remidiation Trust appearing in Cost of Goods Sold									2,563,000	400,000
Loss Contingency, Range of Possible Loss, Minimum											2,000,000
CONSOL Energy's portion of probable recoveries from settled claims									3,805,000
Remaining liability in PCB soil removal action	868,904,000	768,494,000							1,769,000
Loss Contingency, Damages Sought, Value											$ 384,000
Commitments and Contingent, number of asbestos claims			6,900

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Basis of Presentation Anti-Dilutive Options and Units Exluded from Earnings Per Share (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share	6,775,624	8,078,413	6,775,624	2,927,548
Antidilutive Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share	4,833,174	5,740,444	4,833,174	2,412,502
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share	1,243,207	1,348,046	1,243,207	13,302
Performance Share Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share	97,142	488,179	97,142	0
Performance Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from the computation of diluted earnings per share	602,101	501,744	602,101	501,744

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Pension and OPEB - Periodic Cost (Tables)

9 Months Ended

Sep. 30, 2013

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS NET PERIODIC BENEFIT COSTS: [Abstract]

Components of Net Periodic Costs

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

	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	4,897		$	5,527		$	16,184		$	15,530		$	4,849		$	4,525		$	14,547		$	14,291
Interest cost	9,497			9,396			27,249			28,190			29,619			33,687			88,856			102,008
Expected return on plan assets	(13,336		)	(11,538		)	(38,191		)	(34,617		)	—			—			—			—
Amortization of prior service credits	(408		)	(408		)	(1,223		)	(1,223		)	(7,804		)	(13,409		)	(23,411		)	(38,418		)
Recognized net actuarial loss	8,042			11,959			30,764			35,876			17,595			20,255			52,784			60,620
Settlement loss	6,296			—			38,498			—			—			—			—			—
Net periodic benefit cost	$	14,988		$	14,936		$	73,281		$	43,756		$	44,259		$	45,058		$	132,776		$	138,501

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Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2013

BASIS OF PRESENTATION: [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Weighted average shares of common stock outstanding:
Basic	228,876,336			227,654,395			228,640,671			227,491,284
Effect of stock-based compensation awards	—			—			—			1,700,586
Dilutive	228,876,336			227,654,395			228,640,671			229,191,870
Earnings per share:
Basic	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.04

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]

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 September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Anti-Dilutive Options	4,833,174	5,740,444	4,833,174	2,412,502
Anti-Dilutive Restricted Stock Units	1,243,207	1,348,046	1,243,207	13,302
Anti-Dilutive Performance Share Units	97,142	488,179	97,142	—
Anti-Dilutive Performance Share Options	602,101	501,744	602,101	501,744
	6,775,624	8,078,413	6,775,624	2,927,548

Schedule of Changes in Accumulated Other Comprehensive Income/(Loss) by Component [Table Text Block]

Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows:

	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	40,400			61,912			102,312
Amounts reclassified from accumulated other comprehensive income	(56,595		)	51,729			(4,866		)
New current period other comprehensive income	(16,195		)	113,641			97,446
Balance at September 30, 2013	$	60,566		$	(710,462	)	$	(649,896	)

Schedule of Reclassification of Adjustments to Accumulated Other Comprehensive Income [Table Text Block]

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Derivative Instruments (Note 12)
Natural gas price swaps	$	(38,379	)	$	(77,492	)	$	(93,146	)	$	(251,357	)
Tax benefit	14,025			29,683			36,551			97,760
Net of tax	$	(24,354	)	$	(47,809	)	$	(56,595	)	$	(153,597	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(8,212	)	$	(13,915	)	$	(24,635	)	$	(39,937	)
Recognized net actuarial loss	21,055			26,611			69,802			79,688
Settlement loss	6,296			—			38,498			—
Total	19,139			12,696			83,665			39,751
Tax expense	(7,306		)	(4,775		)	(31,936		)	(14,946		)
Net of tax	$	11,833		$	7,921		$	51,729		$	24,805

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Options	11,655	108,477	256,768	159,611
Restricted Stock Units	130,523	22,025	698,664	548,492
Performance Share Units	—	—	159,228	229,730
	142,178	130,502	1,114,660	937,833

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CWP and Workers Comp - Net Periodic Costs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Schedule of Net Periodic Benefit Costs and Assumptions for Defined Benefit Postretirement Plans [Line Items]
Amortization of actuarial gain	$ (21,055)	$ (26,611)	$ (69,802)	$ (79,688)
Net periodic (benefit) cost	19,139	12,696	83,665	39,751
Coal Workers Pneumoconiosis [Member]
Schedule of Net Periodic Benefit Costs and Assumptions for Defined Benefit Postretirement Plans [Line Items]
Service cost	2,135	1,927	6,405	5,783
Interest cost	1,808	1,991	5,424	5,973
Amortization of actuarial gain	(4,213)	(4,933)	(12,638)	(14,799)
State administrative fees and insurance bond premiums	0	0	0	0
Legal and administrative costs	0	0	0	0
Net periodic (benefit) cost	(270)	(1,015)	(809)	(3,043)
Payments for Coal Workers Pnenumoconiosis			7,879
Workers Compensation [Member]
Schedule of Net Periodic Benefit Costs and Assumptions for Defined Benefit Postretirement Plans [Line Items]
Service cost	3,533	3,634	10,599	10,903
Interest cost	1,655	1,778	4,966	5,335
Amortization of actuarial gain	(699)	(986)	(2,098)	(2,958)
State administrative fees and insurance bond premiums	1,496	1,795	4,500	5,340
Legal and administrative costs	591	648	1,773	1,943
Net periodic (benefit) cost	6,576	6,869	19,740	20,563
Payments for workers compensation benefits, state administrative fees and surety bond premiums			$ 21,271

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring Basis [Table Text Block]

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

	Fair Value Measurements at September 30, 2013						Fair Value Measurements at December 31, 2012
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	$	—	$	102,114	$	—	$	—	$	128,945	$	—

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]

	September 30, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	21,086		$	21,086		$	21,878		$	21,878
Restricted Cash (a)	$	12,263		$	12,263		$	68,673		$	68,673
Short-Term Notes Payable	$	(47,000	)	$	(47,000	)	$	(25,073	)	$	(25,073	)
Borrowings Under Securitization Facility	$	(44,364	)	$	(44,364	)	$	(37,846	)	$	(37,846	)
Long-Term Debt	$	(3,128,361	)	$	(3,320,618	)	$	(3,129,017	)	$	(3,378,058	)

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Basis of Presentation Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (63,651)	$ (11,368)	$ (77,741)	$ 238,567
Weighted average shares of common stock outstanding:
Basic	228,876,336	227,654,395	228,640,671	227,491,284
Effect of stock-based compensation awards	0	0	0	1,700,586
Dilutive	228,876,336	227,654,395	228,640,671	229,191,870
Earnings Per Share:
Basic	$ (0.28)	$ (0.05)	$ (0.34)	$ 1.05
Dilutive	$ (0.28)	$ (0.05)	$ (0.34)	$ 1.04

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Income Taxes Tax Examinations (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Tax Examination [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	$ 6,004,000
Income Tax Reconciliation, Nondeductible Expense, Depletion		111,104,000	53,932,000
Internal Revenue Service (IRS) [Member]
Income Tax Examination [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	983,000
Foreign Tax Authority [Member]
Income Tax Examination [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	$ 1,786,000

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Long-term Debt, Other Disclosures [Abstract]

Schedule of Long-term Debt

	September 30, 2013		December 31, 2012
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
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.43% weighted average interest rate for September 30, 2013 and December 31, 2012)	20,394		20,394
Other long-term notes maturing at various dates through 2031 (total value of $6,268 and $7,300 less unamortized discount of $1,166 and $1,542 at September 30, 2013 and December 31, 2012, respectively).	5,102		5,758
	3,128,361		3,129,017
Less amounts due in one year *	4,606		4,544
Long-Term Debt	$	3,123,755	$	3,124,473

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Industry Segment Results (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Sales-Outside	$ 1,160,114	$ 1,084,041	$ 3,512,055	$ 3,584,805
Sales-Purchased Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	1,188,791	1,125,392	3,598,914	3,748,150
Earnings Before Income Taxes	10,574	(31,371)	11,084	298,861
Total Assets	12,737,072	12,556,594	12,737,072	12,556,594	12,670,909
Depreciation, Depletion and Amortization	169,152	153,877	489,774	463,048
Capital Expenditures	437,909	437,622	1,195,909	1,152,021
Equity in Earnings of Unconsolidated Affiliates			(20,276)	(22,676)
Investments in Unconsolidated Equity Affiliates	261,218		261,218		222,830
Total Reportable Business Segments
Segment Reporting Information [Line Items]
Earnings Before Income Taxes	83,938	19,468	237,668	452,763
Total Assets	11,787,041	11,465,377	11,787,041	11,465,377
Coal
Segment Reporting Information [Line Items]
Sales-Outside	889,002	831,309	2,732,458	2,830,395
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	900,565	858,739	2,768,207	2,956,590
Earnings Before Income Taxes	85,805	7,804	244,785	427,455
Total Assets	5,792,969	5,594,926	5,792,969	5,594,926
Depreciation, Depletion and Amortization	104,530	95,702	307,992	297,148
Capital Expenditures	156,730	254,864	511,626	702,880
Equity in Earnings of Unconsolidated Affiliates	(1,682)	(3,504)	10,661	7,588
Investments in Unconsolidated Equity Affiliates	20,131	19,750	20,131	19,750
Gas
Segment Reporting Information [Line Items]
Sales-Outside	192,782	165,102	531,860	473,404
Sales-Purchased Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	601	345	2,363	1,171
Total Sales and Freight	210,497	179,368	585,333	511,725
Earnings Before Income Taxes	(1,867)	11,664	(7,117)	25,308
Total Assets	5,994,072	5,870,451	5,994,072	5,870,451
Depreciation, Depletion and Amortization	58,444	52,215	163,079	148,344
Capital Expenditures	273,474	166,617	669,067	408,278
Equity in Earnings of Unconsolidated Affiliates	5,307	2,503	9,519	6,484
Investments in Unconsolidated Equity Affiliates	183,895	135,048	183,895	135,048
All Other Segments [Member]
Segment Reporting Information [Line Items]
Sales-Outside	78,330	87,630	247,737	281,006
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	32,213	37,987	100,118	111,332
Total Sales and Freight	110,543	125,617	347,855	392,338
Earnings Before Income Taxes	(6,991)	8,494	(48,426)	27,539
Total Assets	356,848	376,400	356,848	376,400
Depreciation, Depletion and Amortization	6,178	0	18,703	0
Capital Expenditures	7,705	16,141	15,216	40,863
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Sales-Outside	0	0	0	0
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	(32,814)	(38,332)	(102,481)	(112,503)
Total Sales and Freight	(32,814)	(38,332)	(102,481)	(112,503)
Earnings Before Income Taxes	(66,373)	(59,333)	(178,158)	(181,441)
Total Assets	593,183	714,817	593,183	714,817
Depreciation, Depletion and Amortization	0	5,960	0	17,556
Capital Expenditures	0	0	0	0
All Other
Segment Reporting Information [Line Items]
Equity in Earnings of Unconsolidated Affiliates	(16)	8,574	96	8,604
Investments in Unconsolidated Equity Affiliates	57,192	58,910	57,192	58,910
Steam [Member] | Coal
Segment Reporting Information [Line Items]
Sales-Outside	753,692	667,372	2,212,909	2,227,728
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	753,692	667,372	2,212,909	2,227,728
Earnings Before Income Taxes	128,112	89,743	360,312	351,889
Low Volatile Metallurgical [Member] | Coal
Segment Reporting Information [Line Items]
Sales-Outside	98,232	110,239	356,066	403,460
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	98,232	110,239	356,066	403,460
Earnings Before Income Taxes	21,295	42,722	106,831	164,843
High Volatile Metallurgical [member] | Coal
Segment Reporting Information [Line Items]
Sales-Outside	29,608	48,484	145,345	180,302
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	29,608	48,484	145,345	180,302
Earnings Before Income Taxes	6,466	9,640	37,063	44,994
Other Coal [Member] | Coal
Segment Reporting Information [Line Items]
Sales-Outside	7,470	5,214	18,138	18,905
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	19,033	32,644	53,887	145,100
Earnings Before Income Taxes	(70,068)	(134,301)	(259,421)	(134,271)
Coalbed Methane [Member] | Gas
Segment Reporting Information [Line Items]
Sales-Outside	83,269	94,169	254,708	281,784
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	83,269	94,169	254,708	281,784
Earnings Before Income Taxes	20,909	30,983	64,345	91,717
Marcellus Shale [Member] | Gas
Segment Reporting Information [Line Items]
Sales-Outside	72,406	36,253	167,394	83,774
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	72,406	36,253	167,394	83,774
Earnings Before Income Taxes	27,941	6,347	53,389	14,433
Conventional Gas [Member] | Gas
Segment Reporting Information [Line Items]
Sales-Outside	32,957	32,288	99,138	100,868
Sales-Purchased Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Total Sales and Freight	32,957	32,288	99,138	100,868
Earnings Before Income Taxes	(2,124)	(3,439)	(11,861)	(9,571)
Other Gas | Gas
Segment Reporting Information [Line Items]
Sales-Outside	4,150	2,392	10,620	6,978
Sales-Purchased Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	601	345	2,363	1,171
Total Sales and Freight	21,865	16,658	64,093	45,299
Earnings Before Income Taxes	(48,593)	(22,227)	(112,990)	(71,271)
First Energy [Member] | Coal
Segment Reporting Information [Line Items]
Entity-Wide Revenue, Major Customer, Amount	164,572	129,014	492,872	409,745
XCoal Energy and Resources [Member] | Coal
Segment Reporting Information [Line Items]
Entity-Wide Revenue, Major Customer, Amount	$ 119,707		$ 441,528	$ 382,950

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Related Party Transaction (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	50.00%		50.00%
CONE [Member]
Related Party Transaction [Line Items]
Due from Related Parties	$ 1,563		$ 1,563		$ 3,142
Related Party Transaction, Expenses from Transactions with Related Party	9,498	5,895	22,954	13,619
CONE [Member] | CONE Capital Reimbursement [Member]
Related Party Transaction [Line Items]
Due from Related Parties	0		0		(18)
CONE [Member] | Reimbursement for CONE Expenses [Member]
Related Party Transaction [Line Items]
Due from Related Parties	(1,380)		(1,380)		(1,336)
CONE [Member] | Reimbursement for Services Provided to Cone [Member]
Related Party Transaction [Line Items]
Due from Related Parties	(181)		(181)		(341)
CONE [Member] | CONE Gathering Fees [Member]
Related Party Transaction [Line Items]
Due to Related Parties, Current	$ 3,124		$ 3,124		$ 4,837

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Carrying Amounts and Fair Values of Financial Instruments for Which the Fair Value Option Was Not Elected (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Option, Disclosures Related to Election, Items Existing at Effective Date [Line Items]
Restricted Cash and Cash Equivalents, Current	$ 12,263	$ 48,294
Cash and Cash Equivalents	21,086	21,878	230,958	375,736
Notes and Loans Payable, Current	(47,000)	(25,073)
Secured Debt, Current	(44,364)	(37,846)
Long-term debt	(3,128,361)	(3,129,017)
Restricted Cash and Cash Equivalents, Noncurrent	0	20,379
Carrying Amount
Fair Value, Option, Disclosures Related to Election, Items Existing at Effective Date [Line Items]
Restricted Cash and Cash Equivalents, Current	12,263	48,294
Cash and Cash Equivalents	21,086	21,878
Restricted cash	12,263	68,673
Long-term debt	(3,128,361)	(3,129,017)
Restricted Cash and Cash Equivalents, Noncurrent		20,379
Fair Value
Fair Value, Option, Disclosures Related to Election, Items Existing at Effective Date [Line Items]
Cash and Cash Equivalents	21,086	21,878
Restricted cash	12,263	68,673
Long-term debt	$ (3,320,618)	$ (3,378,058)

XML

Dispositions (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	3 Months Ended					12 Months Ended		3 Months Ended		12 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2013 Belmont County, Ohio Reserves [Member] T	Sep. 30, 2013 Crowsnest Pass [Member] Rate	Sep. 30, 2013 Potamac Coal Reserves [Member]	Sep. 30, 2013 Robinson Run Longwall Shields [Member] [Member]	Jun. 30, 2012 Burning Star Disposal [Member]	Dec. 31, 2012 Ram River [Member] acre	Dec. 31, 2012 Burning Start No.4 [Member] acre	Sep. 30, 2013 Shoemaker Longwall Shields [Member]	Sep. 30, 2013 Bailey Longwall Shields [Member]	Dec. 31, 2012 Youngs Creek [Member] acre	Jun. 30, 2012 Elk Creek Disposal [Member]	Dec. 31, 2012 Elk Creek [Member] acre
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Tons sold		1,500
Sale Leaseback Transaction, Net Proceeds					$ 68,337				$ 63,839	$ 71,166
Coal Lands and or Surface Rights							36,000	4,300			200,000,000		20,000
Proceeds from Sale of Property, Plant, and Equipment	583,942	2,300	24,764	25,000		13,023	51,869				169,500	26,000
Increase (Decrease) of Restricted Investments			12,263
Disposal Group, Including Discontinued Operation, Assets of Disposal Group											.5
Gain (Loss) on Disposition of Assets		2,300	15,260	24,663		11,261	89,943				150,677	11,235
Interest in Property Sold			50.00%
Gain (Loss) on Sale of Property Plant Equipment					(236)				279	358
royalty percentage retained		.03									.08
Note Receivable 1 year - PPE Sale							25,500
Note Receivable 2 year - PPE Sale							24,500
Restricted Cash and Cash Equivalents							48,294
Transaction and Financing Fees							$ 637

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Guarantor Subsidiaries Balance Sheet (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Current Assets:
Cash and Cash Equivalents	$ 21,086	$ 21,878	$ 230,958	$ 375,736
Accounts and Notes Receivable:
Trade	436,388	428,328
Notes Receivable, Related Parties, Current	25,813	318,387
Other Receivables	160,931	131,131
Accounts Receivable - Securitized	44,364	37,846
Inventories	238,348	247,766
Deferred Income Taxes	81,825	148,104
Restricted Cash and Cash Equivalents, Current	12,263	48,294
Prepaid Expenses	162,418	157,360
Total Current Assets	1,183,436	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	16,571,104	15,545,204
Less-Accumulated Depreciation, Depletion and Amortization	5,940,247	5,354,237
Total Property, Plant and Equipment-Net	10,630,857	10,190,967
Other Assets:
Deferred Income Taxes	457,105	444,585
Restricted Cash and Cash Equivalents, Noncurrent	0	20,379
Investments in Unconsolidated Equity Affiliates	261,218	222,830
Notes, Loans and Financing Receivable, Net	155	25,977
Other	204,301	227,077
Total Other Assets	922,779	940,848
Total Assets	12,737,072	12,670,909	12,556,594
Current Liabilities:
Accounts Payable	512,182	507,982
Accounts Payable (Recoverable)- Related Parties	0	0
Short-Term Notes Payable		25,073
Current Portion Long-Term Debt	13,182	13,485
Short-Term Notes Payable	47,000	25,073
Secured Debt, Current	44,364	37,846
Accrued Income Taxes, Current	87,965	34,219
Other Accrued Liabilities	868,904	768,494
Total Current Liabilities	1,573,597	1,387,099
Long-Term Debt:	3,171,931	3,174,586
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	2,814,234	2,832,401
Pneumoconiosis	178,508	174,781
Mine Closing	460,515	446,727
Gas Well Closing	197,093	148,928
Workers' Compensation	156,568	155,648
Salary Retirement	74,108	218,004
Reclamation	49,487	47,965
Other	103,855	131,025
Total Deferred Credits and Other Liabilities	4,034,368	4,155,479
Total CONSOL Energy Inc. Stockholders' Equity	3,958,165	3,953,792
Noncontrolling Interest	(989)	(47)
TOTAL LIABILITIES AND EQUITY	12,737,072	12,670,909
Parent Issuer [Member]
Current Assets:
Cash and Cash Equivalents	16,187	17,491
Accounts and Notes Receivable:
Trade	0	0
Notes Receivable, Related Parties, Current	1,193	154
Other Receivables	3,866	6,335
Accounts Receivable - Securitized	0	0
Inventories	0	0
Deferred Income Taxes	106,291	174,176
Restricted Cash and Cash Equivalents, Current	0	0
Prepaid Expenses	37,054	29,589
Total Current Assets	164,591	227,745
Property, Plant and Equipment:
Property, Plant and Equipment	218,303	216,448
Less-Accumulated Depreciation, Depletion and Amortization	139,157	126,048
Total Property, Plant and Equipment-Net	79,146	90,400
Other Assets:
Deferred Income Taxes	875,354	884,310
Restricted Cash and Cash Equivalents, Noncurrent		0
Investments in Unconsolidated Equity Affiliates	10,234,178	9,917,050
Notes, Loans and Financing Receivable, Net	155	239
Other	109,998	118,938
Total Other Assets	11,219,685	10,920,537
Total Assets	11,463,422	11,238,682
Current Liabilities:
Accounts Payable	193,491	177,734
Accounts Payable (Recoverable)- Related Parties	3,882,644	3,599,216
Short-Term Notes Payable		25,073
Current Portion Long-Term Debt	1,454	1,554
Short-Term Notes Payable	0
Secured Debt, Current	0	0
Accrued Income Taxes, Current	64,059	20,488
Other Accrued Liabilities	209,321	135,407
Total Current Liabilities	4,350,969	3,959,472
Long-Term Debt:	3,004,976	3,005,515
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	0	0
Pneumoconiosis	0	0
Mine Closing	0	0
Gas Well Closing	0	0
Workers' Compensation	0	0
Salary Retirement	74,108	218,004
Reclamation	0	0
Other	75,204	101,899
Total Deferred Credits and Other Liabilities	149,312	319,903
Total CONSOL Energy Inc. Stockholders' Equity	3,958,165	3,953,792
Noncontrolling Interest	0	0
TOTAL LIABILITIES AND EQUITY	11,463,422	11,238,682
CNX Gas Guarantor [Member]
Current Assets:
Cash and Cash Equivalents	3,847	3,352
Accounts and Notes Receivable:
Trade	60,255	58,126
Notes Receivable, Related Parties, Current	0	315,730
Other Receivables	144,253	214,748
Accounts Receivable - Securitized	0	0
Inventories	15,679	14,133
Deferred Income Taxes	(24,466)	(26,072)
Restricted Cash and Cash Equivalents, Current	0	0
Prepaid Expenses	81,970	86,186
Total Current Assets	281,538	666,203
Property, Plant and Equipment:
Property, Plant and Equipment	6,586,647	5,956,207
Less-Accumulated Depreciation, Depletion and Amortization	1,122,401	960,613
Total Property, Plant and Equipment-Net	5,464,246	4,995,594
Other Assets:
Deferred Income Taxes	(418,249)	(439,725)
Restricted Cash and Cash Equivalents, Noncurrent		0
Investments in Unconsolidated Equity Affiliates	183,895	143,876
Notes, Loans and Financing Receivable, Net	0	0
Other	39,916	65,935
Total Other Assets	(194,438)	(229,914)
Total Assets	5,551,346	5,431,883
Current Liabilities:
Accounts Payable	257,487	166,182
Accounts Payable (Recoverable)- Related Parties	39,594	23,981
Short-Term Notes Payable		0
Current Portion Long-Term Debt	6,036	5,953
Short-Term Notes Payable	85,500
Secured Debt, Current	0	0
Accrued Income Taxes, Current	23,906	13,731
Other Accrued Liabilities	70,835	57,074
Total Current Liabilities	483,358	266,921
Long-Term Debt:	43,682	46,081
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	0	0
Pneumoconiosis	0	0
Mine Closing	0	0
Gas Well Closing	118,075	80,097
Workers' Compensation	0	0
Salary Retirement	0	0
Reclamation	0	0
Other	12,227	24,518
Total Deferred Credits and Other Liabilities	130,302	104,615
Total CONSOL Energy Inc. Stockholders' Equity	4,894,993	5,014,313
Noncontrolling Interest	(989)	(47)
TOTAL LIABILITIES AND EQUITY	5,551,346	5,431,883
Other Guarantors Subsidiaries [Member]
Current Assets:
Cash and Cash Equivalents	0	175
Accounts and Notes Receivable:
Trade	0	0
Notes Receivable, Related Parties, Current	24,620	2,503
Other Receivables	7,780	33,289
Accounts Receivable - Securitized	0	0
Inventories	184,877	198,269
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Current	12,263	48,294
Prepaid Expenses	41,981	40,215
Total Current Assets	271,521	322,745
Property, Plant and Equipment:
Property, Plant and Equipment	9,740,510	9,347,370
Less-Accumulated Depreciation, Depletion and Amortization	4,659,763	4,249,507
Total Property, Plant and Equipment-Net	5,080,747	5,097,863
Other Assets:
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Noncurrent		20,379
Investments in Unconsolidated Equity Affiliates	750,771	769,058
Notes, Loans and Financing Receivable, Net	0	25,738
Other	44,822	32,016
Total Other Assets	795,593	847,191
Total Assets	6,147,861	6,267,799
Current Liabilities:
Accounts Payable	48,128	154,936
Accounts Payable (Recoverable)- Related Parties	(4,202,168)	(3,749,584)
Short-Term Notes Payable		0
Current Portion Long-Term Debt	4,914	5,222
Short-Term Notes Payable	0
Secured Debt, Current	0	0
Accrued Income Taxes, Current	0	0
Other Accrued Liabilities	578,019	566,485
Total Current Liabilities	(3,571,107)	(3,022,941)
Long-Term Debt:	121,864	121,523
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	2,814,234	2,832,401
Pneumoconiosis	178,508	174,781
Mine Closing	460,515	446,727
Gas Well Closing	79,018	68,831
Workers' Compensation	156,242	155,342
Salary Retirement	0	0
Reclamation	49,487	47,965
Other	16,424	4,608
Total Deferred Credits and Other Liabilities	3,754,428	3,730,655
Total CONSOL Energy Inc. Stockholders' Equity	5,842,676	5,438,562
Noncontrolling Interest	0	0
TOTAL LIABILITIES AND EQUITY	6,147,861	6,267,799
Non-Guarantors [Member]
Current Assets:
Cash and Cash Equivalents	1,052	860
Accounts and Notes Receivable:
Trade	376,133	370,202
Notes Receivable, Related Parties, Current	0	0
Other Receivables	5,032	5,159
Accounts Receivable - Securitized	44,364	37,846
Inventories	37,792	35,364
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Current	0	0
Prepaid Expenses	1,413	1,370
Total Current Assets	465,786	450,801
Property, Plant and Equipment:
Property, Plant and Equipment	25,644	25,179
Less-Accumulated Depreciation, Depletion and Amortization	18,926	18,069
Total Property, Plant and Equipment-Net	6,718	7,110
Other Assets:
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Noncurrent		0
Investments in Unconsolidated Equity Affiliates	0	0
Notes, Loans and Financing Receivable, Net	0	0
Other	9,565	10,188
Total Other Assets	9,565	10,188
Total Assets	482,069	468,099
Current Liabilities:
Accounts Payable	13,076	9,130
Accounts Payable (Recoverable)- Related Parties	241,430	254,787
Short-Term Notes Payable		0
Current Portion Long-Term Debt	778	756
Short-Term Notes Payable	0
Secured Debt, Current	44,364	37,846
Accrued Income Taxes, Current	0	0
Other Accrued Liabilities	10,729	9,528
Total Current Liabilities	310,377	312,047
Long-Term Debt:	1,409	1,467
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	0	0
Pneumoconiosis	0	0
Mine Closing	0	0
Gas Well Closing	0	0
Workers' Compensation	326	306
Salary Retirement	0	0
Reclamation	0	0
Other	0	0
Total Deferred Credits and Other Liabilities	326	306
Total CONSOL Energy Inc. Stockholders' Equity	169,957	154,279
Noncontrolling Interest	0	0
TOTAL LIABILITIES AND EQUITY	482,069	468,099
Consolidation, Eliminations [Member]
Current Assets:
Cash and Cash Equivalents	0	0
Accounts and Notes Receivable:
Trade	0	0
Notes Receivable, Related Parties, Current	0	0
Other Receivables	0	(128,400)
Accounts Receivable - Securitized	0	0
Inventories	0	0
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Current	0	0
Prepaid Expenses	0	0
Total Current Assets	0	(128,400)
Property, Plant and Equipment:
Property, Plant and Equipment	0	0
Less-Accumulated Depreciation, Depletion and Amortization	0	0
Total Property, Plant and Equipment-Net	0	0
Other Assets:
Deferred Income Taxes	0	0
Restricted Cash and Cash Equivalents, Noncurrent		0
Investments in Unconsolidated Equity Affiliates	(10,907,626)	(10,607,154)
Notes, Loans and Financing Receivable, Net	0	0
Other	0	0
Total Other Assets	(10,907,626)	(10,607,154)
Total Assets	(10,907,626)	(10,735,554)
Current Liabilities:
Accounts Payable	0	0
Accounts Payable (Recoverable)- Related Parties	38,500	(128,400)
Short-Term Notes Payable		0
Current Portion Long-Term Debt	0	0
Short-Term Notes Payable	(38,500)
Secured Debt, Current	0	0
Accrued Income Taxes, Current	0	0
Other Accrued Liabilities	0	0
Total Current Liabilities	0	(128,400)
Long-Term Debt:	0	0
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	0	0
Pneumoconiosis	0	0
Mine Closing	0	0
Gas Well Closing	0	0
Workers' Compensation	0	0
Salary Retirement	0	0
Reclamation	0	0
Other	0	0
Total Deferred Credits and Other Liabilities	0	0
Total CONSOL Energy Inc. Stockholders' Equity	(10,907,626)	(10,607,154)
Noncontrolling Interest	0	0
TOTAL LIABILITIES AND EQUITY	$ (10,907,626)	$ (10,735,554)

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Subsequent Event (Notes)

9 Months Ended

Sep. 30, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

SUBSEQUENT EVENT:

On October 25, 2013, CONSOL Energy entered into an agreement to sell Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy).  The CCC mines being sold are McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 28.5 million tons of thermal coal in 2012. Murray Energy is acquiring approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations are included in the transaction. In 2012, the fleet of 21 towboats and 600 barges transported 19.3 million tons of coal and other commodities along the upper Ohio River system. CONSOL Energy will receive $850,000 in cash as a result of the transaction and in addition Murray Energy will assume certain employee and environmental related liabilities with a book value of approximately $2,400,000 at September 30, 2013. The final financial gain will be calculated upon closing, which is expected to occur during the fourth quarter.

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Consolidated Balance Sheets (Parentheticals) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Common Stock [Member]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	228,936,248	228,129,467
Common Stock, Shares, Outstanding	228,936,248	228,094,712
Treasury Stock, Shares	0	34,755
Preferred Stock [Member]
Preferred Stock, Shares Authorized	15,000,000	15,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating Activities:
Net Income (Loss)	$ (78,683)	$ 238,433
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	489,774	463,048
Stock-Based Compensation	50,914	38,423
(Gain) Loss on Sale of Assets	(52,794)	(190,257)
Amortization of Mineral Leases	2,014	3,818
Deferred Income Taxes	(31,099)	(5,225)
Equity in Earnings of Affiliates	(20,276)	(22,676)
Changes in Operating Assets:
Accounts and Notes Receivable	11,145	13,359
Inventories	9,418	(8,204)
Prepaid Expenses	(9,259)	(1,362)
Changes in Other Assets	24,318	(8,961)
Changes in Operating Liabilities:
Accounts Payable	(20,553)	5,218
Other Operating Liabilities	174,740	(11,130)
Changes in Other Liabilities	8,148	1,469
Other	31,198	14,210
Net Cash Provided by Operating Activities	589,005	530,163
Investing Activities:
Capital Expenditures	(1,195,909)	(1,152,021)
Increase (Decrease) in Restricted Cash	56,410	0
Proceeds from Sales of Assets	598,174	583,942
Net Investment in Equity Affiliates	(18,112)	(18,701)
Net Cash Used in Investing Activities	(559,437)	(586,780)
Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	47,000
Payments on Miscellaneous Borrowings	(32,290)	(6,565)
Payments on Securitzation Facility	6,518	0
Tax Benefit from Stock-Based Compensation	2,316	2,578
Dividends Paid	(57,211)	(85,290)
Proceeds from Issuance of Common Stock	2,698	1,234
Issuance of Treasury Stock	609	109
Debt Issuance and Financing Fees	0	(227)
Net Cash (Used in) Provided by Financing Activities	(30,360)	(88,161)
Net Increase in Cash and Cash Equivalents	(792)	(144,778)
Cash and Cash Equivalents at Beginning of Period	21,878	375,736
Cash and Cash Equivalents at End of Period	$ 21,086	$ 230,958

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Pension and OPEB - Periodic Cost

9 Months Ended

Sep. 30, 2013

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS NET PERIODIC BENEFIT COSTS: [Abstract]

Components of Pension and Other Postretirement Benefit Plans:

COMPONENTS OF PENSION AND OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:

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

	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	4,897		$	5,527		$	16,184		$	15,530		$	4,849		$	4,525		$	14,547		$	14,291
Interest cost	9,497			9,396			27,249			28,190			29,619			33,687			88,856			102,008
Expected return on plan assets	(13,336		)	(11,538		)	(38,191		)	(34,617		)	—			—			—			—
Amortization of prior service credits	(408		)	(408		)	(1,223		)	(1,223		)	(7,804		)	(13,409		)	(23,411		)	(38,418		)
Recognized net actuarial loss	8,042			11,959			30,764			35,876			17,595			20,255			52,784			60,620
Settlement loss	6,296			—			38,498			—			—			—			—			—
Net periodic benefit cost	$	14,988		$	14,936		$	73,281		$	43,756		$	44,259		$	45,058		$	132,776		$	138,501

For the nine months ended September 30, 2013, $55,272 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 2013. CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Net periodic benefit costs are allocated to Costs of Goods Sold and Other Operating Charges and Selling, General and Administrative Expenses in the Consolidated Statements of Income.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three and nine months ended September 30, 2013. Accordingly, CONSOL Energy recognized expense of $6,296 and $38,498 for the three and nine months ended September 30, 2013, respectively, in Costs of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement charges noted above also resulted in a remeasurement of the pension plan at September 30, June 30, and March 31, 2013. The September 30, 2013 remeasurement resulted in a change to the discount rate to 4.80% from 4.84% at June 30, 2013. The September remeasurement reduced the pension liability by $21,264. The September settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $17,040 in Other Comprehensive Income, net of $10,520 in deferred taxes. It is reasonably possible that CONSOL Energy will incur additional settlement charges in 2013, which would require the pension plan to be remeasured using updated assumptions.

CONSOL Energy does not expect to contribute to the other post-employment benefit plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $124,504 of other post-employment benefits have been paid.

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Subsequent Event (Details) (USD $)	1 Months Ended
	Oct. 25, 2013 T
Subsequent Events [Abstract]
Subsequent Event, Date	Oct. 25, 2013
Subsequent Event, Description	CONSOL Energy entered into an agreement to sell Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy).  The CCC mines being sold are McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine.
Tons Produced in 2012	28,500
reserves sold	1,100
Towboats Sold	$ 21,000
Barges Sold	600,000
2012 TONS TRANSPORTED BY RIVER DIVISION	19,300
Cash Received	850,000
Book Value of Liabilites Assumed	$ 2,400,000.00

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2013

BASIS OF PRESENTATION: [Abstract]

Basis of Presentation

BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2012 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, 2012 included in CONSOL Energy Inc.'s Form 10-K.

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2012, with no effect on previously reported net income or stockholders' equity.

Basic earnings per share are computed by dividing net (loss) income attributable to shareholders 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, performance stock options, and CONSOL share units, 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, performance share options, and CONSOL share units were exercised, that outstanding restricted stock units 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 September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Anti-Dilutive Options	4,833,174	5,740,444	4,833,174	2,412,502
Anti-Dilutive Restricted Stock Units	1,243,207	1,348,046	1,243,207	13,302
Anti-Dilutive Performance Share Units	97,142	488,179	97,142	—
Anti-Dilutive Performance Share Options	602,101	501,744	602,101	501,744
	6,775,624	8,078,413	6,775,624	2,927,548

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Options	11,655	108,477	256,768	159,611
Restricted Stock Units	130,523	22,025	698,664	548,492
Performance Share Units	—	—	159,228	229,730
	142,178	130,502	1,114,660	937,833

The weighted average exercise price per share of the options exercised during the three months ended September 30, 2013 and 2012 was $17.40 and $7.13, respectively. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2013 and 2012 was $10.49 and $8.39, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Weighted average shares of common stock outstanding:
Basic	228,876,336			227,654,395			228,640,671			227,491,284
Effect of stock-based compensation awards	—			—			—			1,700,586
Dilutive	228,876,336			227,654,395			228,640,671			229,191,870
Earnings per share:
Basic	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.04

Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows:

	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	40,400			61,912			102,312
Amounts reclassified from accumulated other comprehensive income	(56,595		)	51,729			(4,866		)
New current period other comprehensive income	(16,195		)	113,641			97,446
Balance at September 30, 2013	$	60,566		$	(710,462	)	$	(649,896	)

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Derivative Instruments (Note 12)
Natural gas price swaps	$	(38,379	)	$	(77,492	)	$	(93,146	)	$	(251,357	)
Tax benefit	14,025			29,683			36,551			97,760
Net of tax	$	(24,354	)	$	(47,809	)	$	(56,595	)	$	(153,597	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(8,212	)	$	(13,915	)	$	(24,635	)	$	(39,937	)
Recognized net actuarial loss	21,055			26,611			69,802			79,688
Settlement loss	6,296			—			38,498			—
Total	19,139			12,696			83,665			39,751
Tax expense	(7,306		)	(4,775		)	(31,936		)	(14,946		)
Net of tax	$	11,833		$	7,921		$	51,729		$	24,805

*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the three months and nine months ended September 30, 2013 and September 30, 2012.

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Basis of Presentation Changes in Accumulated Other Comprehensive Income / (Loss) by component (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Natural Gas Swaps	$ (38,379)	$ (77,492)	$ (93,146)	$ (251,357)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(649,896)		(649,896)		(747,342)
Other Comprehensive Income (Loss), Net of Tax	13,872	(46,347)	97,446	1,763
Tax Benefit of Natural Gas Swaps	14,025	29,683	36,551	97,760
Natural Gas Swaps, Net of Tax	(24,354)	(47,809)	(56,595)	(153,597)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(8,212)	(13,915)	(24,635)	(39,937)
Defined Benefit Plan, Amortization of Gains (Losses)	21,055	26,611	69,802	79,688
Other Comprehensive Income (Loss), Finalization of Pension and Non-Pension Postretirement Plan Valuation, Net of Tax	(6,296)		38,498
Defined Benefit Plan, Net Periodic Benefit Cost	19,139	12,696	83,665	39,751
Tax Expense on Actuarially Determined Long-Term Liabilities	7,306	4,775	(31,936)	(14,946)
Actuarially Determined Long-Term Liability Adjustments, Net of Tax	11,833	7,921	51,729	24,805
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(649,896)		(649,896)		(747,342)
Other Comprehensive Income (Loss), Net of Tax			97,446
Amounts reclassified from accumulated other comprehensive income			(4,866)
Other comprehensive income before reclassifications			102,312
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	60,566		60,566		76,761
Other Comprehensive Income (Loss), Net of Tax			(16,195)
Amounts reclassified from accumulated other comprehensive income			(56,595)
Other comprehensive income before reclassifications			40,400
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(710,462)		(710,462)		(824,103)
Other Comprehensive Income (Loss), Net of Tax			113,641
Amounts reclassified from accumulated other comprehensive income			51,729
Other comprehensive income before reclassifications			61,912
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(408)	(408)	(1,223)	(1,223)
Defined Benefit Plan, Amortization of Gains (Losses)	(8,042)	(11,959)	(30,764)	(35,876)
Other Comprehensive Income (Loss), Finalization of Pension and Non-Pension Postretirement Plan Valuation, Net of Tax	(6,296)	0	(38,498)	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ 14,988	$ 14,936	$ 73,281	$ 43,756

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CWP and Workers Comp - Net Periodic Costs (Tables)

9 Months Ended

Sep. 30, 2013

CWP And Workers Comp Net Periodic Costs [Abstract]

Components of Net Periodic Benefit Costs

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

	CWP												Workers' Compensation
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2,135		$	1,927		$	6,405		$	5,783		$	3,533		$	3,634		$	10,599		$	10,903
Interest cost	1,808			1,991			5,424			5,973			1,655			1,778			4,966			5,335
Amortization of actuarial gain	(4,213		)	(4,933		)	(12,638		)	(14,799		)	(699		)	(986		)	(2,098		)	(2,958		)
State administrative fees and insurance bond premiums	—			—			—			—			1,496			1,795			4,500			5,340
Legal and administrative costs	—			—			—			—			591			648			1,773			1,943
Net periodic (benefit) cost	$	(270	)	$	(1,015	)	$	(809	)	$	(3,043	)	$	6,576		$	6,869		$	19,740		$	20,563

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Commitments and Contingencies (Tables)

3 Months Ended

Sep. 30, 2013

Long-term Purchase Commitment [Table Text Block]

At September 30, 2013, 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	$	190,358	$	71,624	$	118,734	$	—	$	—
Environmental	56,294		54,566		1,728		—		—
Other	83,246		34,488		48,758		—		—
Total Letters of Credit	329,898		160,678		169,220		—		—
Surety Bonds:
Employee-Related	204,884		204,884		—		—		—
Environmental	537,167		495,017		42,150		—		—
Other	31,955		31,719		235		—		1
Total Surety Bonds	774,006		731,620		42,385		—		1
Total Commitments	$	1,103,904	$	892,298	$	211,605	$	—	$	1

Unrecorded Unconditional Purchase Obligations Disclosure

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheet. As of September 30, 2013, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due	Amount
Less than 1 year	$	393,709
1 - 3 years	253,025
3 - 5 years	189,138
More than 5 years	419,240
Total Purchase Obligations	$	1,255,112

Supply Commitment [Table Text Block]

Costs related to these purchase obligations include:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Major equipment purchases	$	8,990	$	59,799	$	57,571	$	104,980
Firm transportation expense	29,654		18,844		89,196		49,711
Gas drilling obligations	26,296		27,100		81,419		85,192
Other	—		65		—		492
Total costs related to purchase obligations	$	64,940	$	105,808	$	228,186	$	240,375

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Guarantor Subsidiaries Financial Information Gurantor Subsidiaries Statement of Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	$ (64,049)	$ (11,473)	$ (78,683)	$ 238,433
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	24,980	7,921	113,641	75,080
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	13,246	(6,459)	40,400	80,280
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(24,354)	(47,809)	(56,595)	(153,597)
Other Comprehensive Income (Loss), Net of Tax	13,872	(46,347)	97,446	1,763
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(50,177)	(57,820)	18,763	240,196
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	398	105	942	134
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(49,779)	(57,715)	19,705	240,330
Parent Issuer [Member]
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	(63,651)	(11,368)	(77,741)	238,567
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(24,980)	(7,921)	(113,641)	(75,080)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(13,246)	6,459	(40,400)	(80,280)
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	24,354	47,809	56,595	153,597
Other Comprehensive Income (Loss), Net of Tax	(13,872)	46,347	(97,446)	(1,763)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(49,779)	(57,715)	19,705	240,330
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(49,779)	(57,715)	19,705	240,330
CNX Gas Guarantor [Member]
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	(993)	7,096	(4,067)	15,276
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	0	0	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(13,246)	6,459	(40,400)	(80,280)
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	24,354	47,809	56,595	153,597
Other Comprehensive Income (Loss), Net of Tax	11,108	54,268	16,195	73,317
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(12,101)	(47,172)	(20,262)	(58,041)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	398	105	942	134
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(11,703)	(47,067)	(19,320)	(57,907)
Other Guarantors Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	103,541	143,542	424,891	390,443
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(24,980)	(7,921)	(113,641)	(75,080)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0	0	0	0
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	0	0	0	0
Other Comprehensive Income (Loss), Net of Tax	(24,980)	(7,921)	(113,641)	(75,080)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	128,521	151,463	538,532	465,523
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	128,521	151,463	538,532	465,523
Non-Guarantors [Member]
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	3,106	2,424	12,904	9,600
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	0	0	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0	0	0	0
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	0	0	0	0
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	3,106	2,424	12,904	9,600
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	3,106	2,424	12,904	9,600
Consolidation, Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net Income (Loss)	(106,052)	(153,167)	(434,670)	(415,453)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	24,980	7,921	113,641	75,080
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	13,246	(6,459)	40,400	80,280
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(24,354)	(47,809)	(56,595)	(153,597)
Other Comprehensive Income (Loss), Net of Tax	13,872	(46,347)	97,446	1,763
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(119,924)	(106,820)	(532,116)	(417,216)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (119,924)	$ (106,820)	$ (532,116)	$ (417,216)

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Related Party Transaction (Tables)

3 Months Ended

Sep. 30, 2013

NOTE 16- RELATED PARTY TRANSACTIONS [Abstract]

Related Party Receivables Payables [Table Text Block]

	September 30,			December 31,
	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(1,380	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(181		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	3,124			4,837			Accounts Payable
Net Payable due CONE	$	1,563		$	3,142

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Guarantor Subsidiaries, Condensed Statement of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	$ 589,005	$ 530,163
Investing Activities:
Capital Expenditures	(1,195,909)	(1,152,021)
Net Cash Used in Investing Activities	(559,437)	(586,780)
Financing Activities:
Dividends Paid	(57,211)	(85,290)
Proceeds from Issuance of Common Stock	2,698	1,234
(Payments on) Proceeds from Short-Term Borrowings	47,000
Other Financing Activities	2,925	(2,871)
Payments on Securitization Facility	6,518
Repayments of Other Debt	(32,290)	(6,565)
Net Cash (Used in) Provided by Financing Activities	(30,360)	(88,161)
Equity Method Investment, Dividends or Distributions	(18,112)	(18,701)
Proceeds from Sale of Property, Plant, and Equipment		583,942
Increase (Decrease) in Restricted Cash	56,410	0
Payments for (Proceeds from) Other Investing Activities	(598,174)
Parent Issuer [Member]
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	(7,813)	(245,017)
Investing Activities:
Capital Expenditures	(15,216)	(40,863)
Net Cash Used in Investing Activities	(15,216)	128,637
Financing Activities:
Dividends Paid	42,789	114,710
Proceeds from Issuance of Common Stock	2,698
(Payments on) Proceeds from Short-Term Borrowings	0
Other Financing Activities	2,925	3,304
Payments on Securitization Facility	0
Repayments of Other Debt	(26,591)
Net Cash (Used in) Provided by Financing Activities	21,821	118,014
Equity Method Investment, Dividends or Distributions	0	0
Proceeds from Sale of Property, Plant, and Equipment		169,500
Increase (Decrease) in Restricted Cash	0
Payments for (Proceeds from) Other Investing Activities	0
CNX Gas Guarantor [Member]
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	383,504	139,026
Investing Activities:
Capital Expenditures	(669,067)	(408,278)
Net Cash Used in Investing Activities	(364,425)	(80,292)
Financing Activities:
Dividends Paid	(100,000)	(200,000)
Proceeds from Issuance of Common Stock	0
(Payments on) Proceeds from Short-Term Borrowings	85,500
Other Financing Activities	(4,084)	(4,107)
Payments on Securitization Facility	0
Repayments of Other Debt	0
Net Cash (Used in) Provided by Financing Activities	(18,584)	(204,107)
Equity Method Investment, Dividends or Distributions	(30,500)	(31,650)
Proceeds from Sale of Property, Plant, and Equipment		359,636
Increase (Decrease) in Restricted Cash	0
Payments for (Proceeds from) Other Investing Activities	(335,142)
Other Guarantors Subsidiaries [Member]
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	180,580	635,257
Investing Activities:
Capital Expenditures	(511,626)	(702,880)
Net Cash Used in Investing Activities	(179,813)	(635,175)
Financing Activities:
Dividends Paid	0	0
Proceeds from Issuance of Common Stock	0
(Payments on) Proceeds from Short-Term Borrowings	0
Other Financing Activities	4,084	(1,729)
Payments on Securitization Facility	0
Repayments of Other Debt	(5,122)
Net Cash (Used in) Provided by Financing Activities	(1,038)	(1,729)
Equity Method Investment, Dividends or Distributions	12,388	12,949
Proceeds from Sale of Property, Plant, and Equipment		54,756
Increase (Decrease) in Restricted Cash	56,410
Payments for (Proceeds from) Other Investing Activities	(263,015)
Non-Guarantors [Member]
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	(5,766)	897
Investing Activities:
Capital Expenditures	0	0
Net Cash Used in Investing Activities	17	50
Financing Activities:
Dividends Paid	0	0
Proceeds from Issuance of Common Stock	0
(Payments on) Proceeds from Short-Term Borrowings	0
Other Financing Activities	0	(339)
Payments on Securitization Facility	6,518
Repayments of Other Debt	(577)
Net Cash (Used in) Provided by Financing Activities	5,941	(339)
Equity Method Investment, Dividends or Distributions	0	0
Proceeds from Sale of Property, Plant, and Equipment		50
Increase (Decrease) in Restricted Cash	0
Payments for (Proceeds from) Other Investing Activities	(17)
Consolidation, Eliminations [Member]
Schedule of Condensed Consolidating Statement of Cash Flows [Line Items]
Net Cash Provided by Operating Activities	38,500	0
Investing Activities:
Capital Expenditures	0	0
Net Cash Used in Investing Activities	0	0
Financing Activities:
Dividends Paid	0	0
Proceeds from Issuance of Common Stock	0
(Payments on) Proceeds from Short-Term Borrowings	(38,500)
Other Financing Activities	0	0
Payments on Securitization Facility	0
Repayments of Other Debt	0
Net Cash (Used in) Provided by Financing Activities	(38,500)	0
Equity Method Investment, Dividends or Distributions	0	0
Proceeds from Sale of Property, Plant, and Equipment		0
Increase (Decrease) in Restricted Cash	0
Payments for (Proceeds from) Other Investing Activities	$ 0

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Short-Term Notes Payable (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
Short-term Debt [Line Items]
Interest Payable, Current	$ 113,589	$ 113,589	$ 63,363
Senior Secured Credit Facility April122016 Member [Member]
Short-term Debt [Line Items]
Credit facility, face amount			1,500,000
Additional Capacity Available On Credit Lines At Request	250,000	250,000
Minimum interest coverage ratio	2.50
Interest coverage ratio	3.96	3.96
Maximum leverage ratio	4.50
Current maximum leverage ratio	3.21
Senior secured leverage ratio, maximum	2.00	2.00
Current secured leverage ratio	0.11	0.11
Letters of credit outstanding	104,137	104,137	100,292
Borrowings and issuance of letters of credit remaining capacity	1,395,863	1,395,863	1,399,708
CNX Gas Senior Secured Credit Facility April122016 Member [Member]
Short-term Debt [Line Items]
Credit facility, face amount			1,000,000
Short-term Debt	47,000	47,000
Additional Capacity Available On Credit Lines At Request	250,000	250,000
loans, advances, dividends allowed	600,000	600,000
Minimum interest coverage ratio	3.00
Interest coverage ratio	28.55	28.55
Maximum leverage ratio	3.50
Current maximum leverage ratio	0.75
Letters of credit outstanding	70,051	70,051	70,203
Borrowings and issuance of letters of credit remaining capacity	882,949	882,949	929,797
Debt Instrument, Interest Rate During Period	1.80%	1.76%
Interest Payable, Current	5	5		29
Interim Funding for Longwall Shields [Member]
Short-term Debt [Line Items]
Short-term Debt			$ 25,073
Debt Instrument, Interest Rate, Stated Percentage	2.46%	2.46%

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Income Taxes Discrete Items (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Tax Carryforward [Line Items]
Income Tax Reconciliation, Nondeductible Expense, Depletion			$ 111,104,000	$ 53,932,000
Unusual or Infrequent, Tax Effect	8,467,000		4,701,000
Tax Adjustments, Settlements, and Unusual Provisions		6,004,000
State and Local Jurisdiction [Member]
Other Tax Carryforward [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions			1,585,000
Northern Powder River Basin Assets [Member]
Other Tax Carryforward [Line Items]
Unusual or Infrequent, Tax Effect		$ 48,976,000

XML

Pension and OPEB - Periodic Cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 Pension Plans, Defined Benefit [Member]	Sep. 30, 2012 Pension Plans, Defined Benefit [Member]	Sep. 30, 2013 Pension Plans, Defined Benefit [Member]	Sep. 30, 2012 Pension Plans, Defined Benefit [Member]	Sep. 30, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2013 Change in Assumptions for Pension Plans [Member] Pension Plans, Defined Benefit [Member] Rate	Jun. 30, 2013 Change in Assumptions for Pension Plans [Member] Pension Plans, Defined Benefit [Member] Rate
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost						$ 4,897	$ 5,527	$ 16,184	$ 15,530	$ 4,849	$ 4,525	$ 14,547	$ 14,291
Interest cost						9,497	9,396	27,249	28,190	29,619	33,687	88,856	102,008
Expected return on plan assets						(13,336)	(11,538)	(38,191)	(34,617)	0	0	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(8,212)	(13,915)	(24,635)	(39,937)		(408)	(408)	(1,223)	(1,223)	(7,804)	(13,409)	(23,411)	(38,418)
Amortization of actuarial gain	(21,055)	(26,611)	(69,802)	(79,688)		8,042	11,959	30,764	35,876	17,595	20,255	52,784	60,620
Other Comprehensive Income (Loss), Finalization of Pension and Non-Pension Postretirement Plan Valuation, Net of Tax	6,296		(38,498)			6,296	0	38,498	0	0	0	0	0
Net periodic (benefit) cost	19,139	12,696	83,665	39,751		14,988	14,936	73,281	43,756	44,259	45,058	132,776	138,501
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate														4.80%	4.84%
Pension Contributions								55,272
Defined Benefit Plan, Plan Amendments														21,264
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(24,980)	(7,921)	(113,641)	(75,080)										17,040
Deferred Income Taxes	81,825		81,825		148,104									10,520
Defined Benefit Plan, Benefits Paid												$ 124,504

XML

Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest [Abstract]
Net Income (Loss)	$ (64,049)	$ (11,473)	$ (78,683)	$ 238,433
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	24,980	7,921	113,641	75,080
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	13,246	(6,459)	40,400	80,280
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]
Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(24,354)	(47,809)	(56,595)	(153,597)
Other Comprehensive Income (Loss), Net of Tax	13,872	(46,347)	97,446	1,763
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(50,177)	(57,820)	18,763	240,196
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	(398)	(105)	(942)	(134)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (49,779)	$ (57,715)	$ 19,705	$ 240,330

XML

Inventories

9 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventories

INVENTORIES:

Inventory components consist of the following:

	September 30, 2013		December 31, 2012
Coal	$	58,050	$	78,825
Merchandise for resale	37,792		35,363
Supplies	142,506		133,578
Total Inventories	$	238,348	$	247,766

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead, depreciation, depletion and amortization, and other related costs.

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $18,683 and $19,700 at September 30, 2013 and December 31, 2012, respectively.

XML

Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and Cash Equivalents	$ 21,086	$ 21,878
Accounts and Notes Receivable:
Trade	436,388	428,328
Notes, Loans and Financing Receivable, Net, Current	25,813	318,387
Other Receivables	160,931	131,131
Accounts Receivable - Securitized	44,364	37,846
Inventories	238,348	247,766
Deferred Income Taxes	81,825	148,104
Restricted Cash and Cash Equivalents, Current	12,263	48,294
Prepaid Expenses	162,418	157,360
Total Current Assets	1,183,436	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	16,571,104	15,545,204
Less-Accumulated Depreciation, Depletion and Amortization	5,940,247	5,354,237
Total Property, Plant and Equipment-Net	10,630,857	10,190,967
Other Assets:
Deferred Income Taxes	457,105	444,585
Restricted Cash	0	20,379
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	261,218	222,830
Notes, Loans and Financing Receivable, Net, Noncurrent	155	25,977
Other	204,301	227,077
Total Other Assets	922,779	940,848
Total Assets	12,737,072	12,670,909
Current Liabilities:
Accounts Payable	512,182	507,982
Current Portion of Long-Term Debt	13,182	13,485
Short-Term Notes Payable	47,000	25,073
Accrued Income Taxes, Current	87,965	34,219
Secured Debt, Current	44,364	37,846
Other Accrued Liabilities	868,904	768,494
Total Current Liabilities	1,573,597	1,387,099
Long-Term Debt:
Long-Term Debt	3,123,755	3,124,473
Capital Lease Obligations	48,176	50,113
Total Long-Term Debt	3,171,931	3,174,586
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	2,814,234	2,832,401
Pneumoconiosis Benefits	178,508	174,781
Mine Closing	460,515	446,727
Gas Well Closing	197,093	148,928
Workers' Compensation	156,568	155,648
Salary Retirement	74,108	218,004
Reclamation	49,487	47,965
Other	103,855	131,025
Total Deferred Credits and Other Liabilities	4,034,368	4,155,479
TOTAL LIABILITIES	8,779,896	8,717,164
Stockholders' Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,936,248 Issued and Outstanding at September 30, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012	2,292	2,284
Capital in Excess of Par Value	2,347,973	2,296,908
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	0	0
Retained Earnings	2,257,796	2,402,551
Accumulated Other Comprehensive Loss	(649,896)	(747,342)
Common Stock in Treasury, at Cost—No Shares at September 30, 2013 and 34,755 Shares at December 31, 2012	0	(609)
Stockholders' Equity Attributable to Parent	3,958,165	3,953,792
Stockholders' Equity Attributable to Noncontrolling Interest	(989)	(47)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,957,176	3,953,745
TOTAL LIABILITIES AND EQUITY	$ 12,737,072	$ 12,670,909

XML

Unrecorded Unconditional Purchase Obligation (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,103,904
Purchase Commitment [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Less than 1 year	393,709
1 - 3 years	253,025
3 - 5 years	189,138
More than 5 years	419,240
Total Purchase Obligations	1,255,112
Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	892,298
More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	211,605
More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1
Standby Letters of Credit [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	329,898
Standby Letters of Credit [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	160,678
Standby Letters of Credit [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	169,220
Standby Letters of Credit [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Standby Letters of Credit [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Surety Bonds [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	774,006
Surety Bonds [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	731,620
Surety Bonds [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	42,385
Surety Bonds [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Surety Bonds [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1
Employee Related Commitments [Member] | Standby Letters of Credit [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	190,358
Employee Related Commitments [Member] | Standby Letters of Credit [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	71,624
Employee Related Commitments [Member] | Standby Letters of Credit [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	118,734
Employee Related Commitments [Member] | Standby Letters of Credit [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Employee Related Commitments [Member] | Standby Letters of Credit [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Employee Related Commitments [Member] | Surety Bonds [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	204,884
Employee Related Commitments [Member] | Surety Bonds [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	204,884
Employee Related Commitments [Member] | Surety Bonds [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Employee Related Commitments [Member] | Surety Bonds [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Employee Related Commitments [Member] | Surety Bonds [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Environment Related Commitments [Member] | Standby Letters of Credit [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	56,294
Environment Related Commitments [Member] | Standby Letters of Credit [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	54,566
Environment Related Commitments [Member] | Standby Letters of Credit [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,728
Environment Related Commitments [Member] | Standby Letters of Credit [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Environment Related Commitments [Member] | Standby Letters of Credit [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Environment Related Commitments [Member] | Surety Bonds [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	537,167
Environment Related Commitments [Member] | Surety Bonds [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	495,017
Environment Related Commitments [Member] | Surety Bonds [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	42,150
Environment Related Commitments [Member] | Surety Bonds [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Environment Related Commitments [Member] | Surety Bonds [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Other Commitments [Member] | Standby Letters of Credit [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	83,246
Other Commitments [Member] | Standby Letters of Credit [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	34,488
Other Commitments [Member] | Standby Letters of Credit [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	48,758
Other Commitments [Member] | Standby Letters of Credit [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Other Commitments [Member] | Standby Letters of Credit [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Other Commitments [Member] | Surety Bonds [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	31,955
Other Commitments [Member] | Surety Bonds [Member] | Balance on First Anniversary [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	31,719
Other Commitments [Member] | Surety Bonds [Member] | More Than One And Within Three Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	235
Other Commitments [Member] | Surety Bonds [Member] | More Than Three And Within Five Years From Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	0
Other Commitments [Member] | Surety Bonds [Member] | Beyond Five Years of Balance Sheet Date [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1

XML

Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]
Sales-Outside	$ 1,160,114	$ 1,084,041	$ 3,512,055	$ 3,584,805
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Sales-Purchased Gas	1,608	953	4,372	2,443
Freight-Outside	11,563	27,430	35,749	126,195
Other Income (including equity earnings)	42,627	34,697	138,824	293,196
Total Revenue and Other Income	1,231,418	1,160,089	3,737,738	4,041,346
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	851,088	827,530	2,639,929	2,588,460
Gas Royalty Interests Costs	12,864	10,543	38,204	27,916
Purchased Gas Costs	941	737	2,961	2,123
Freight Expense	11,563	27,430	35,749	126,195
Selling, General and Administrative Expenses	33,472	36,681	104,265	109,412
Depreciation, Depletion and Amortization	169,152	153,877	489,774	463,048
Interest Expense	56,301	54,075	164,197	168,788
Taxes Other Than Income	85,463	80,587	251,575	256,543
Total Costs	1,220,844	1,191,460	3,726,654	3,742,485
Earnings Before Income Taxes	10,574	(31,371)	11,084	298,861
Income Tax Expense (Benefit)	74,623	(19,898)	89,767	60,428
Net Income (Loss)	(64,049)	(11,473)	(78,683)	238,433
Add: Net Loss Attributable to Noncontrolling Interest	(398)	(105)	(942)	(134)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (63,651)	$ (11,368)	$ (77,741)	$ 238,567
Earnings Per Share:
Basic	$ (0.28)	$ (0.05)	$ (0.34)	$ 1.05
Dilutive	$ (0.28)	$ (0.05)	$ (0.34)	$ 1.04
Weighted Average Number of Common Shares Outstanding:
Basic	228,876,336	227,654,395	228,640,671	227,491,284
Dilutive	228,876,336	227,654,395	228,640,671	229,191,870
Dividends Paid Per Share	$ 0.125	$ 0.125	$ 0.250	$ 0.375

XML

Inventory Components (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Coal	$ 58,050	$ 78,825
Merchandise for resale	37,792	35,363
Supplies	142,506	133,578
Total Inventories	238,348	247,766
Excess of replacement cost of merchandise for resl inventories over carrying LIFO value	$ 18,683	$ 19,700

XML

Inventories (Tables)

9 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventory components

	September 30, 2013		December 31, 2012
Coal	$	58,050	$	78,825
Merchandise for resale	37,792		35,363
Supplies	142,506		133,578
Total Inventories	$	238,348	$	247,766

XML

Related Party Transaction

3 Months Ended

Sep. 30, 2013

Related Party Transaction [Line Items]

Related Party Transactions Disclosure [Text Block]

RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the the three and nine months ended September 30, 2013, 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 $9,498 and $22,954 for the three and nine months ended September 30, 2013, respectively, and were $5,895 and $13,619 for the three and nine months ended September 30, 2012, respectively, which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of September 30, 2013 and December 31, 2012, CONSOL Energy and CNX Gas Company had a net payable of $1,563 and $3,142, respectively, due CONE which was comprised of the following items:

	September 30,			December 31,
	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(1,380	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(181		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	3,124			4,837			Accounts Payable
Net Payable due CONE	$	1,563		$	3,142

XML

Acquisitions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2013 Rate
Allegheny County Airport – Allegheny County Airport [Member]
Business Acquisition [Line Items]
Bonus Payment in Escrow	7.60%
Interest in Property Sold	50.00%
Bonus Payment	$ 46,315
Ryerson Dam and Lake [Member]
Business Acquisition [Line Items]
Business Acquisition, Contingent Consideration, Potential Cash Payment	36,000
Gas and Oil Area, Undeveloped, Gross	506,000
Bonus Payment	$ 13,728
Allegheny County Airport – Pittsburgh International Airport [Member] [Member]
Business Acquisition [Line Items]
Gas and Oil Area, Undeveloped, Gross	9,300

XML

Property, Plant and Equipment Joint Venture Activity (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013 Noble JV[Member] [Member]	Sep. 30, 2013 Hess [Member]	Sep. 30, 2013 Noble JV[Member] [Member] acre	Dec. 31, 2011 Noble JV[Member] [Member] acre	Sep. 30, 2011 Noble JV[Member] [Member]	Dec. 31, 2011 Hess [Member] Rate acre
Joint Venture Interest Percentage						50.00%		50.00%
Drilling commitment carry							$ 2,100,000,000	$ 534,000,000
Three Month Average Price Carry for carry not to be suspended							4.00
Joint Venture Percent of Carry in Drilling Obligations								0.50
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Net of Tax						64,142,000		53,095,000
Acres in Joint Venture primarily focused on								73,000,000
Acres in Joint Venture to be sold								63,000,000
Maximum Annual Drilling Commitment Carry							400,000,000
Acres w/ Asserted Title Defects					86,498,000			39,000,000
Gas and Oil Acreage, Unproved, Net						628,000		200,000
Cash Proceeds Related to Joint Venture Activity						485,464,000		54,254,000
Joint Venture Transaction Fees						34,998,000		5,719,000
Note Receivable 1 year - joint venture proceed						311,754,000
Note receivable 2 year - joint venture proceeds						296,344,000
Cash Proceeds Related to 1 year Note						327,964,000
Oil and Gas Joint Interest Billing Receivables						16,703,000
Payable Related to Joint Venture Activity						980,000
Cash Proceeds Related to Receivable						15,598,000
Carry Value of Acres w/ Asserted Title Defects					543,000,000			153,000,000
Total Value of Asserted Title Defects		204,000,000
Tentative Acres w/ Asserted Title Defects					2,868,000			26,000,000
Carry Value of Tentative Acres w/ Asserted Title Defects					27,000,000
Acres to be reassigned by Joint Venture								65,000,000
drill carry remaining			1,885,785,000	255,148,000				335,000,000
Transaction Value of Asserted Title Defects	$ 12,983,000	$ 21,763,000

XML

Reconciliation of Segment Information, Revenue and Other Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	$ 1,160,114	$ 1,084,041	$ 3,512,055	$ 3,584,805
Earnings Before Income Taxes:
Earnings Before Income Taxes	10,574	(31,371)	11,084	298,861
Revenue from Purchased Oil and Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	1,188,791	1,125,392	3,598,914	3,748,150
Total Assets	12,737,072	12,556,594	12,737,072	12,556,594	12,670,909
Depreciation, Depletion and Amortization	169,152	153,877	489,774	463,048
Capital Expenditures	437,909	437,622	1,195,909	1,152,021
Total Reportable Business Segments
Earnings Before Income Taxes:
Earnings Before Income Taxes	83,938	19,468	237,668	452,763
Total Assets	11,787,041	11,465,377	11,787,041	11,465,377
Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	889,002	831,309	2,732,458	2,830,395
Earnings Before Income Taxes:
Earnings Before Income Taxes	85,805	7,804	244,785	427,455
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	900,565	858,739	2,768,207	2,956,590
Total Assets	5,792,969	5,594,926	5,792,969	5,594,926
Depreciation, Depletion and Amortization	104,530	95,702	307,992	297,148
Capital Expenditures	156,730	254,864	511,626	702,880
Gas
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	192,782	165,102	531,860	473,404
Earnings Before Income Taxes:
Earnings Before Income Taxes	(1,867)	11,664	(7,117)	25,308
Revenue from Purchased Oil and Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	601	345	2,363	1,171
Segment Reporting Information, Revenue for Reportable Segment	210,497	179,368	585,333	511,725
Total Assets	5,994,072	5,870,451	5,994,072	5,870,451
Depreciation, Depletion and Amortization	58,444	52,215	163,079	148,344
Capital Expenditures	273,474	166,617	669,067	408,278
All Other Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	78,330	87,630	247,737	281,006
Earnings Before Income Taxes:
Earnings Before Income Taxes	(6,991)	8,494	(48,426)	27,539
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	32,213	37,987	100,118	111,332
Segment Reporting Information, Revenue for Reportable Segment	110,543	125,617	347,855	392,338
Total Assets	356,848	376,400	356,848	376,400
Depreciation, Depletion and Amortization	6,178	0	18,703	0
Capital Expenditures	7,705	16,141	15,216	40,863
Excludes Gas Segment [Member]
Earnings Before Income Taxes:
Interest Income (Expense), Net and Other Non-operating Activity	(57,482)	(56,338)	(166,548)	(175,323)
Fees for Disposing Non-core Assets	(8,891)	(2,995)	11,610	6,118
Intersegment Elimination [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	0	0	0	0
Earnings Before Income Taxes:
Earnings Before Income Taxes	(66,373)	(59,333)	(178,158)	(181,441)
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	(32,814)	(38,332)	(102,481)	(112,503)
Segment Reporting Information, Revenue for Reportable Segment	(32,814)	(38,332)	(102,481)	(112,503)
Total Assets	593,183	714,817	593,183	714,817
Depreciation, Depletion and Amortization	0	5,960	0	17,556
Capital Expenditures	0	0	0	0
Steam [Member] | Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	753,692	667,372	2,212,909	2,227,728
Earnings Before Income Taxes:
Earnings Before Income Taxes	128,112	89,743	360,312	351,889
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	753,692	667,372	2,212,909	2,227,728
High Volatile Metallurgical [member] | Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	29,608	48,484	145,345	180,302
Earnings Before Income Taxes:
Earnings Before Income Taxes	6,466	9,640	37,063	44,994
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	29,608	48,484	145,345	180,302
Low Volatile Metallurgical [Member] | Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	98,232	110,239	356,066	403,460
Earnings Before Income Taxes:
Earnings Before Income Taxes	21,295	42,722	106,831	164,843
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	98,232	110,239	356,066	403,460
Other Coal [Member] | Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	7,470	5,214	18,138	18,905
Earnings Before Income Taxes:
Earnings Before Income Taxes	(70,068)	(134,301)	(259,421)	(134,271)
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	11,563	27,430	35,749	126,195
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	19,033	32,644	53,887	145,100
Coalbed Methane [Member] | Gas
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	83,269	94,169	254,708	281,784
Earnings Before Income Taxes:
Earnings Before Income Taxes	20,909	30,983	64,345	91,717
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	83,269	94,169	254,708	281,784
Marcellus Shale [Member] | Gas
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	72,406	36,253	167,394	83,774
Earnings Before Income Taxes:
Earnings Before Income Taxes	27,941	6,347	53,389	14,433
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	72,406	36,253	167,394	83,774
Conventional Gas [Member] | Gas
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	32,957	32,288	99,138	100,868
Earnings Before Income Taxes:
Earnings Before Income Taxes	(2,124)	(3,439)	(11,861)	(9,571)
Revenue from Purchased Oil and Gas	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	0	0	0	0
Segment Reporting Information, Revenue for Reportable Segment	32,957	32,288	99,138	100,868
Other Gas | Gas
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales-Outside	4,150	2,392	10,620	6,978
Earnings Before Income Taxes:
Earnings Before Income Taxes	(48,593)	(22,227)	(112,990)	(71,271)
Revenue from Purchased Oil and Gas	1,608	953	4,372	2,443
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Freight-Outside	0	0	0	0
Segment Reporting Information, Intersegment Revenue	601	345	2,363	1,171
Segment Reporting Information, Revenue for Reportable Segment	21,865	16,658	64,093	45,299
First Energy [Member] | Coal
Segment Reporting, Revenue Reconciling Item [Line Items]
Entity-Wide Revenue, Major Customer, Amount	$ 164,572	$ 129,014	$ 492,872	$ 409,745

XML

Basis of Presentation Share-based Compensation (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	142,178	130,502	1,114,660	937,833
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity awards other than options, vested	0	0	159,228	229,730
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Exercised	11,655	108,477	256,768	159,611
Share-based comp Options Granted Weighted average exercise price	$ 17.40	$ 7.13	$ 10.49	$ 8.39
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity awards other than options, vested	130,523	22,025	698,664	548,492

XML

Segment Information (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Segment Reporting [Abstract]

Industry segment results

	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	$	753,692	$	98,232	$	29,608	$	7,470		$	889,002	$	83,269	$	72,406	$	32,957		$	4,150		$	192,782		$	78,330		$	—		$	1,160,114	(A)
Sales—purchased gas	—		—		—		—			—		—		—		—			1,608			1,608			—			—			1,608
Sales—gas royalty interests	—		—		—		—			—		—		—		—			15,506			15,506			—			—			15,506
Freight—outside	—		—		—		11,563			11,563		—		—		—			—			—			—			—			11,563
Intersegment transfers	—		—		—		—			—		—		—		—			601			601			32,213			(32,814		)	—
Total Sales and Freight	$	753,692	$	98,232	$	29,608	$	19,033		$	900,565	$	83,269	$	72,406	$	32,957		$	21,865		$	210,497		$	110,543		$	(32,814	)	$	1,188,791
Earnings (Loss) Before Income Taxes	$	128,112	$	21,295	$	6,466	$	(70,068	)	$	85,805	$	20,909	$	27,941	$	(2,124	)	$	(48,593	)	$	(1,867	)	$	(6,991	)	$	(66,373	)	$	10,574	(B)
Segment assets										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(C)
Depreciation, depletion and amortization										$	104,530											$	58,444		$	6,178		$	—		$	169,152
Capital expenditures										$	156,730											$	273,474		$	7,705		$	—		$	437,909

(A)    Included in the Coal segment are sales of $164,572 to First Energy and $119,707 to Xcoal Energy & Resources each comprising over 10% of sales.

(B)     Includes equity in earnings of unconsolidated affiliates of $(1,682), $5,307 and $(16) for Coal, Gas and All Other, respectively.

(C)    Includes investments in unconsolidated equity affiliates of $20,131, $183,895 and $57,192 for Coal, Gas and All Other, respectively.

	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	$	667,372	$	110,239	$	48,484	$	5,214		$	831,309	$	94,169	$	36,253	$	32,288		$	2,392		$	165,102	$	87,630	$	—		$	1,084,041		(D)
Sales—purchased gas	—		—		—		—			—		—		—		—			953			953		—		—			953
Sales—gas royalty interests	—		—		—		—			—		—		—		—			12,968			12,968		—		—			12,968
Freight—outside	—		—		—		27,430			27,430		—		—		—			—			—		—		—			27,430
Intersegment transfers	—		—		—		—			—		—		—		—			345			345		37,987		(38,332		)	—
Total Sales and Freight	$	667,372	$	110,239	$	48,484	$	32,644		$	858,739	$	94,169	$	36,253	$	32,288		$	16,658		$	179,368	$	125,617	$	(38,332	)	$	1,125,392
Earnings (Loss) Before Income Taxes	$	89,743	$	42,722	$	9,640	$	(134,301	)	$	7,804	$	30,983	$	6,347	$	(3,439	)	$	(22,227	)	$	11,664	$	8,494	$	(59,333	)	$	(31,371	)	(E)
Segment assets										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594		(F)
Depreciation, depletion and amortization										$	95,702											$	52,215	$	—	$	5,960		$	153,877
Capital expenditures										$	254,864											$	166,617	$	16,141	$	—		$	437,622

(D) Included in the Coal segment are sales of $129,014 to First Energy which comprises over 10% of sales.

(E) Includes equity in earnings of unconsolidated affiliates of $(3,504), $2,503 and $8,574 for Coal, Gas and All Other, respectively.

(F)    Includes investments in unconsolidated equity affiliates of $19,750, $135,048 and $58,910 for Coal, Gas and All Other, respectively.

Industry segment results for the nine months ended September 30, 2013 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	$	2,212,909	$	356,066	$	145,345	$	18,138		$	2,732,458	$	254,708	$	167,394	$	99,138		$	10,620		$	531,860		$	247,737		$	—		$	3,512,055	(G)
Sales—purchased gas	—		—		—		—			—		—		—		—			4,372			4,372			—			—			4,372
Sales—gas royalty interests	—		—		—		—			—		—		—		—			46,738			46,738			—			—			46,738
Freight—outside	—		—		—		35,749			35,749		—		—		—			—			—			—			—			35,749
Intersegment transfers	—		—		—		—			—		—		—		—			2,363			2,363			100,118			(102,481		)	—
Total Sales and Freight	$	2,212,909	$	356,066	$	145,345	$	53,887		$	2,768,207	$	254,708	$	167,394	$	99,138		$	64,093		$	585,333		$	347,855		$	(102,481	)	$	3,598,914
Earnings (Loss) Before Income Taxes	$	360,312	$	106,831	$	37,063	$	(259,421	)	$	244,785	$	64,345	$	53,389	$	(11,861	)	$	(112,990	)	$	(7,117	)	$	(48,426	)	$	(178,158	)	$	11,084	(H)
Segment assets										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(I)
Depreciation, depletion and amortization										$	307,992											$	163,079		$	18,703		$	—		$	489,774
Capital expenditures										$	511,626											$	669,067		$	15,216		$	—		$	1,195,909

(G)    Included in the Coal segment are sales of $492,872 to First Energy and $441,528 to Xcoal Energy & Resources each comprising over 10% of sales.

(H)     Includes equity in earnings of unconsolidated affiliates of $10,661, $9,519 and $96 for Coal, Gas and All Other, respectively.

(I)    Includes investments in unconsolidated equity affiliates of $20,131, $183,895 and $57,192 for Coal, Gas and All Other, respectively.

Industry segment results for the nine months ended September 30, 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	$	2,227,728	$	403,460	$	180,302	$	18,905		$	2,830,395	$	281,784	$	83,774	$	100,868		$	6,978		$	473,404	$	281,006	$	—		$	3,584,805	(J)
Sales—purchased gas	—		—		—		—			—		—		—		—			2,443			2,443		—		—			2,443
Sales—gas royalty interests	—		—		—		—			—		—		—		—			34,707			34,707		—		—			34,707
Freight—outside	—		—		—		126,195			126,195		—		—		—			—			—		—		—			126,195
Intersegment transfers	—		—		—		—			—		—		—		—			1,171			1,171		111,332		(112,503		)	—
Total Sales and Freight	$	2,227,728	$	403,460	$	180,302	$	145,100		$	2,956,590	$	281,784	$	83,774	$	100,868		$	45,299		$	511,725	$	392,338	$	(112,503	)	$	3,748,150
Earnings (Loss) Before Income Taxes	$	351,889	$	164,843	$	44,994	$	(134,271	)	$	427,455	$	91,717	$	14,433	$	(9,571	)	$	(71,271	)	$	25,308	$	27,539	$	(181,441	)	$	298,861	(K)
Segment assets										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594	(L)
Depreciation, depletion and amortization										$	297,148											$	148,344	$	—	$	17,556		$	463,048
Capital expenditures										$	702,880											$	408,278	$	40,863	$	—		$	1,152,021

(J) Included in the Coal segment are sales of $409,745 to First Energy and $382,950 to Xcoal Energy & Resources each comprising over 10% of sales.

(K) Includes equity in earnings of unconsolidated affiliates of $7,588, $6,484 and $8,604 for Coal, Gas and All Other, respectively.

(L)    Includes investments in unconsolidated equity affiliates of $19,750, $135,048 and $58,910 for Coal, Gas and All Other, respectively.

Reconciliation of Revenue and Operating Income from Segments to Consolidated

Earnings Before Income Taxes:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
Segment Earnings Before Income Taxes for total reportable business segments	$	83,938		$	19,468		$	237,668		$	452,763
Segment (Loss) Earnings Before Income Taxes for all other businesses	(6,991		)	8,494			(48,426		)	27,539
Interest expense, net and other non-operating activity (M)	(57,482		)	(56,338		)	(166,548		)	(175,323		)
Other Corporate Items (M)	(8,891		)	(2,995		)	(11,610		)	(6,118		)
Earnings Before Income Taxes	$	10,574		$	(31,371	)	$	11,084		$	298,861

Reconciliation of Assets and Liabilities from Segment to Consolidated

Total Assets:	September 30,
	2013		2012
Segment assets for total reportable business segments	$	11,787,041	$	11,465,377
Segment assets for all other businesses	356,848		376,400
Items excluded from segment assets:
Cash and other investments (M)	17,988		40,331
Recoverable income taxes	—		12,132
Deferred tax assets	538,930		618,742
Bond issuance costs	36,265		43,612
Total Consolidated Assets	$	12,737,072	$	12,556,594

_________________________ 

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

XML

Guarantor Subsidiaries Financial Information (Tables)

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Condensed Financial Statements, Captions [Line Items]

Guarantor FInancial Statements [Table Text Block] [Table Text Block]

Income Statement for the Three Months Ended September 30, 2013 (unaudited):

	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	193,381		$	911,732		$	54,174		$	827		$	1,160,114
Sales—Gas Royalty Interests	—			15,506			—			—			—			15,506
Sales—Purchased Gas	—			1,608			—			—			—			1,608
Freight—Outside	—			—			11,563			—			—			11,563
Other Income	78,203			12,596			25,103			4,928			(78,203		)	42,627
Total Revenue and Other Income	78,203			223,091			948,398			59,102			(77,376		)	1,231,418
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	37,591			128,402			620,652			54,857			9,586			851,088
Gas Royalty Interests Costs	—			12,874			—			—			(10		)	12,864
Purchased Gas Costs	—			941			—			—			—			941
Related Party Activity	9,710			—			(29,271		)	458			19,103			—
Freight Expense	—			—			11,563			—			—			11,563
Selling, General and Administrative Expenses	—			11,600			21,582			290			—			33,472
Depreciation, Depletion and Amortization	3,288			58,444			106,910			510			—			169,152
Interest Expense	52,165			2,578			1,548			13			(3		)	56,301
Taxes Other Than Income	165			9,847			74,730			721			—			85,463
Total Costs	102,919			224,686			807,714			56,849			28,676			1,220,844
Earnings (Loss) Before Income Taxes	(24,716		)	(1,595		)	140,684			2,253			(106,052		)	10,574
Income Tax Expense (Benefit)	38,935			(602		)	37,143			(853		)	—			74,623
Net (Loss) Income	(63,651		)	(993		)	103,541			3,106			(106,052		)	(64,049		)
Add: Net Loss Attributable to Noncontrolling Interest	—			398			—			—			—			398
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(63,651	)	$	(595	)	$	103,541		$	3,106		$	(106,052	)	$	(63,651	)

Income Statement for the Three Months Ended September 30, 2012 (unaudited):

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	165,448	$	861,009		$	58,405	$	(821	)	$	1,084,041
Sales—Gas Royalty Interests	—			12,968		—			—		—			12,968
Sales—Purchased Gas	—			953		—			—		—			953
Freight—Outside	—			—		27,430			—		—			27,430
Other Income	(17,948		)	11,772		170,877			4,917		(134,921		)	34,697
Total Revenue and Other Income	(17,948		)	191,141		1,059,316			63,322		(135,742		)	1,160,089
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	18,699			96,619		647,158			57,408		7,646			827,530
Gas Royalty Interests Costs	—			10,565		—			—		(22		)	10,543
Purchased Gas Costs	—			737		—			—		—			737
Related Party Activity	8,575			—		(18,962		)	427		9,960			—
Freight Expense	—			—		27,430			—		—			27,430
Selling, General and Administrative Expenses	—			9,906		26,412			363		—			36,681
Depreciation, Depletion and Amortization	3,085			52,214		98,060			518		—			153,877
Interest Expense	50,811			1,145		2,267			11		(159		)	54,075
Taxes Other Than Income	(504		)	8,426		71,985			680		—			80,587
Total Costs	80,666			179,612		854,350			59,407		17,425			1,191,460
(Loss) Earnings Before Income Taxes	(98,614		)	11,529		204,966			3,915		(153,167		)	(31,371		)
Income Tax (Benefit) Expense	(87,246		)	4,433		61,424			1,491		—			(19,898		)
Net (Loss) Income	(11,368		)	7,096		143,542			2,424		(153,167		)	(11,473		)
Add: Net Loss Attributable to Noncontrolling Interest	—			105		—			—		—			105
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(11,368	)	$	7,201	$	143,542		$	2,424	$	(153,167	)	$	(11,368	)

	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	534,221		$	2,813,430		$	161,837		$	2,567		$	3,512,055
Sales—Gas Royalty Interests	—			46,738			—			—			—			46,738
Sales—Purchased Gas	—			4,372			—			—			—			4,372
Freight—Outside	—			—			35,749			—			—			35,749
Other Income	354,386			37,055			86,064			15,705			(354,386		)	138,824
Total Revenue and Other Income	354,386			622,386			2,935,243			177,542			(351,819		)	3,737,738
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	117,830			359,397			1,971,483			162,050			29,169			2,639,929
Gas Royalty Interests Costs	—			38,235			—			—			(31		)	38,204
Purchased Gas Costs	—			2,961			—			—			—			2,961
Related Party Activity	32,385			—			(87,620		)	1,298			53,937			—
Freight Expense	—			—			35,749			—			—			35,749
Selling, General and Administrative Expenses	—			33,429			69,887			949			—			104,265
Depreciation, Depletion and Amortization	9,735			163,079			315,468			1,492			—			489,774
Interest Expense	153,141			6,375			4,871			34			(224		)	164,197
Taxes Other Than Income	430			25,534			223,254			2,357			—			251,575
Total Costs	313,521			629,010			2,533,092			168,180			82,851			3,726,654
Earnings (Loss) Before Income Taxes	40,865			(6,624		)	402,151			9,362			(434,670		)	11,084
Income Tax Expense (Benefit)	118,606			(2,557		)	(22,740		)	(3,542		)	—			89,767
Net (Loss) Income	(77,741		)	(4,067		)	424,891			12,904			(434,670		)	(78,683		)
Add: Net Loss Attributable to Noncontrolling Interest	—			942			—			—			—			942
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(77,741	)	$	(3,125	)	$	424,891		$	12,904		$	(434,670	)	$	(77,741	)

	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	474,574	$	2,919,814	$	192,212	$	(1,795	)	$	3,584,805
Sales—Gas Royalty Interests	—			34,707		—		—		—			34,707
Sales—Purchased Gas	—			2,443		—		—		—			2,443
Freight—Outside	—			—		126,195		—		—			126,195
Other Income	399,817			46,177		230,930		16,089		(399,817		)	293,196
Total Revenue and Other Income	399,817			557,901		3,276,939		208,301		(401,612		)	4,041,346
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	90,230			296,959		1,992,371		186,635		22,265			2,588,460
Gas Royalty Interests Costs	—			27,951		—		—		(35		)	27,916
Purchased Gas Costs	—			2,123		—		—		—			2,123
Related Party Activity	1,575			—		5,078		1,376		(8,029		)	—
Freight Expense	—			—		126,195		—		—			126,195
Selling, General and Administrative Expenses	—			29,199		79,169		1,044		—			109,412
Depreciation, Depletion and Amortization	8,901			148,343		304,245		1,559		—			463,048
Interest Expense	158,505			3,554		7,056		33		(360		)	168,788
Taxes Other Than Income	159			24,790		229,381		2,213		—			256,543
Total Costs	259,370			532,919		2,743,495		192,860		13,841			3,742,485
Earnings (Loss) Before Income Taxes	140,447			24,982		533,444		15,441		(415,453		)	298,861
Income Tax (Benefit) Expense	(98,120		)	9,706		143,001		5,841		—			60,428
Net Income (Loss)	238,567			15,276		390,443		9,600		(415,453		)	238,433
Add: Net Loss Attributable to Noncontrolling Interest	—			134		—		—		—			134
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	238,567		$	15,410	$	390,443	$	9,600	$	(415,453	)	$	238,567

Guarantor Condensed Cash Flow [Table Text Block]

Cash Flow for the Nine Months EndedSeptember 30, 2013 (unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(7,813	)	$	383,504		$	180,580		$	(5,766	)	$	38,500		$	589,005
Cash Flows from Investing Activities:
Capital Expenditures	$	(15,216	)	$	(669,067	)	$	(511,626	)	$	—		$	—		$	(1,195,909	)
Change in Restricted Cash	—			—			56,410			—			—			56,410
Proceeds from Sales of Assets	—			335,142			263,015			17			—			598,174
Net Investments In Equity Affiliates	—			(30,500		)	12,388			—			—			(18,112		)
Net Cash (Used in) Provided by Investing Activities	$	(15,216	)	$	(364,425	)	$	(179,813	)	$	17		$	—		$	(559,437	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	85,500		$	—		$	—		$	(38,500	)	$	47,000
Payments on Miscellaneous Borrowings	(26,591		)	—			(5,122		)	(577		)	—			(32,290		)
Proceeds from Securitization Facility	—			—			—			6,518			—			6,518
Dividends Received (Paid)	42,789			(100,000		)	—			—			—			(57,211		)
Proceeds from Issuance of Common Stock	2,698			—			—			—			—			2,698
Other Financing Activities	2,925			(4,084		)	4,084			—			—			2,925
Net Cash Provided by (Used in) Financing Activities	$	21,821		$	(18,584	)	$	(1,038	)	$	5,941		$	(38,500	)	$	(30,360	)

Cash Flow for the Nine Months EndedSeptember 30, 2012 (unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(245,017	)	$	139,026		$	635,257		$	897		$	—	$	530,163
Cash Flows from Investing Activities:
Capital Expenditures	$	(40,863	)	$	(408,278	)	$	(702,880	)	$	—		$	—	$	(1,152,021	)
Net Investments In Equity Affiliates	—			(31,650		)	12,949			—			—		(18,701		)
Proceeds from Sales of Assets	169,500			359,636			54,756			50			—		583,942
Net Cash Provided by (Used in) Investing Activities	$	128,637		$	(80,292	)	$	(635,175	)	$	50		$	—	$	(586,780	)
Cash Flows from Financing Activities:
Dividends Received (Paid)	$	114,710		$	(200,000	)	$	—		$	—		$	—	$	(85,290	)
Other Financing Activities	3,304			(4,107		)	(1,729		)	(339		)	—		(2,871		)
Net Cash (Used in) Provided by Financing Activities	$	118,014		$	(204,107	)	$	(1,729	)	$	(339	)	$	—	$	(88,161	)

Guarantor Condensed Comprehensive Income [Table Text Block]

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(63,651	)	$	(993	)	$	103,541	$	3,106	$	(106,052	)	$	(64,049	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	24,980			—			24,980		—		(24,980		)	24,980
Net Increase (Decrease) in the Value of Cash Flow Hedge	13,246			13,246			—		—		(13,246		)	13,246
Reclassification of Cash Flow Hedge from OCI to Earnings	(24,354		)	(24,354		)	—		—		24,354			(24,354		)
Other Comprehensive Income (Loss):	13,872			(11,108		)	24,980		—		(13,872		)	13,872
Comprehensive (Loss) Income	(49,779		)	(12,101		)	128,521		3,106		(119,924		)	(50,177		)
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			398			—		—		—			398
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(49,779	)	$	(11,703	)	$	128,521	$	3,106	$	(119,924	)	$	(49,779	)

Statement of Comprehensive Income for the Three Months Ended September 30, 2012 (Unaudited):

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(11,368	)	$	7,096		$	143,542	$	2,424	$	(153,167	)	$	(11,473	)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	7,921			—			7,921		—		(7,921		)	7,921
Net (Decrease) Increase in the Value of Cash Flow Hedge	(6,459		)	(6,459		)	—		—		6,459			(6,459		)
Reclassification of Cash Flow Hedge from OCI to Earnings	(47,809		)	(47,809		)	—		—		47,809			(47,809		)
Other Comprehensive (Loss) Income:	(46,347		)	(54,268		)	7,921		—		46,347			(46,347		)
Comprehensive (Loss) Income	(57,715		)	(47,172		)	151,463		2,424		(106,820		)	(57,820		)
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			105			—		—		—			105
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(57,715	)	$	(47,067	)	$	151,463	$	2,424	$	(106,820	)	$	(57,715	)

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(77,741	)	$	(4,067	)	$	424,891	$	12,904	$	(434,670	)	$	(78,683	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	113,641			—			113,641		—		(113,641		)	113,641
Net Increase (Decrease) in the Value of Cash Flow Hedge	40,400			40,400			—		—		(40,400		)	40,400
Reclassification of Cash Flow Hedge from OCI to Earnings	(56,595		)	(56,595		)	—		—		56,595			(56,595		)
Other Comprehensive Income (Loss):	97,446			(16,195		)	113,641		—		(97,446		)	97,446
Comprehensive Income (Loss)	19,705			(20,262		)	538,532		12,904		(532,116		)	18,763
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			942			—		—		—			942
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	19,705		$	(19,320	)	$	538,532	$	12,904	$	(532,116	)	$	19,705

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	238,567		$	15,276		$	390,443	$	9,600	$	(415,453	)	$	238,433
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	75,080			—			75,080		—		(75,080		)	75,080
Net Increase (Decrease) in the Value of Cash Flow Hedge	80,280			80,280			—		—		(80,280		)	80,280
Reclassification of Cash Flow Hedge from OCI to Earnings	(153,597		)	(153,597		)	—		—		153,597			(153,597		)
Other Comprehensive Income (Loss):	1,763			(73,317		)	75,080		—		(1,763		)	1,763
Comprehensive Income (Loss)	240,330			(58,041		)	465,523		9,600		(417,216		)	240,196
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			134			—		—		—			134
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	240,330		$	(57,907	)	$	465,523	$	9,600	$	(417,216	)	$	240,330

Guarantor Balance Sheet [Table Text Block]

Balance Sheet at September 30, 2013 (unaudited):

	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	16,187	$	3,847		$	—		$	1,052	$	—		$	21,086
Accounts and Notes Receivable:
Trade	—		60,255			—			376,133		—			436,388
Notes Receivable	1,193		—			24,620			—		—			25,813
Other Receivables	3,866		144,253			7,780			5,032		—			160,931
Accounts Receivable—Securitized	—		—			—			44,364		—			44,364
Inventories	—		15,679			184,877			37,792		—			238,348
Deferred Income Taxes	106,291		(24,466		)	—			—		—			81,825
Restricted Cash	—		—			12,263			—		—			12,263
Prepaid Expenses	37,054		81,970			41,981			1,413		—			162,418
Total Current Assets	164,591		281,538			271,521			465,786		—			1,183,436
Property, Plant and Equipment:
Property, Plant and Equipment	218,303		6,586,647			9,740,510			25,644		—			16,571,104
Less-Accumulated Depreciation, Depletion and Amortization	139,157		1,122,401			4,659,763			18,926		—			5,940,247
Total Property, Plant and Equipment-Net	79,146		5,464,246			5,080,747			6,718		—			10,630,857
Other Assets:
Deferred Income Taxes	875,354		(418,249		)	—			—		—			457,105
Investment in Affiliates	10,234,178		183,895			750,771			—		(10,907,626		)	261,218
Notes Receivable	155		—			—			—		—			155
Other	109,998		39,916			44,822			9,565		—			204,301
Total Other Assets	11,219,685		(194,438		)	795,593			9,565		(10,907,626		)	922,779
Total Assets	$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	193,491	$	257,487		$	48,128		$	13,076	$	—		$	512,182
Accounts Payable (Recoverable)—Related Parties	3,882,644		39,594			(4,202,168		)	241,430		38,500			—
Current Portion Long-Term Debt	1,454		6,036			4,914			778		—			13,182
Short-Term Notes Payable	—		85,500			—			—		(38,500		)	47,000
Accrued Income Taxes	64,059		23,906			—			—		—			87,965
Borrowings Under Securitization Facility	—		—			—			44,364		—			44,364
Other Accrued Liabilities	209,321		70,835			578,019			10,729		—			868,904
Total Current Liabilities	4,350,969		483,358			(3,571,107		)	310,377		—			1,573,597
Long-Term Debt:	3,004,976		43,682			121,864			1,409		—			3,171,931
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			2,814,234			—		—			2,814,234
Pneumoconiosis Benefits	—		—			178,508			—		—			178,508
Mine Closing	—		—			460,515			—		—			460,515
Gas Well Closing	—		118,075			79,018			—		—			197,093
Workers’ Compensation	—		—			156,242			326		—			156,568
Salary Retirement	74,108		—			—			—		—			74,108
Reclamation	—		—			49,487			—		—			49,487
Other	75,204		12,227			16,424			—		—			103,855
Total Deferred Credits and Other Liabilities	149,312		130,302			3,754,428			326		—			4,034,368
Total CONSOL Energy Inc. Stockholders’ Equity	3,958,165		4,894,993			5,842,676			169,957		(10,907,626		)	3,958,165
Noncontrolling Interest	—		(989		)	—			—		—			(989		)
Total Liabilities and Equity	$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072

Balance Sheet at December 31, 2012:

	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	17,491	$	3,352		$	175		$	860	$	—		$	21,878
Accounts and Notes Receivable:
Trade	—		58,126			—			370,202		—			428,328
Notes Receivable	154		315,730			2,503			—		—			318,387
Other Receivables	6,335		214,748			33,289			5,159		(128,400		)	131,131
Accounts Receivable—Securitized	—		—			—			37,846		—			37,846
Inventories	—		14,133			198,269			35,364		—			247,766
Deferred Income Taxes	174,176		(26,072		)	—			—		—			148,104
Restricted Cash	—		—			48,294			—		—			48,294
Prepaid Expenses	29,589		86,186			40,215			1,370		—			157,360
Total Current Assets	227,745		666,203			322,745			450,801		(128,400		)	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	216,448		5,956,207			9,347,370			25,179		—			15,545,204
Less-Accumulated Depreciation, Depletion and Amortization	126,048		960,613			4,249,507			18,069		—			5,354,237
Total Property, Plant and Equipment-Net	90,400		4,995,594			5,097,863			7,110		—			10,190,967
Other Assets:
Deferred Income Taxes	884,310		(439,725		)	—			—		—			444,585
Restricted Cash	—		—			20,379			—		—			20,379
Investment in Affiliates	9,917,050		143,876			769,058			—		(10,607,154		)	222,830
Notes Receivable	239		—			25,738			—		—			25,977
Other	118,938		65,935			32,016			10,188		—			227,077
Total Other Assets	10,920,537		(229,914		)	847,191			10,188		(10,607,154		)	940,848
Total Assets	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	177,734	$	166,182		$	154,936		$	9,130	$	—		$	507,982
Accounts Payable (Recoverable)-Related Parties	3,599,216		23,981			(3,749,584		)	254,787		(128,400		)	—
Current Portion of Long-Term Debt	1,554		5,953			5,222			756		—			13,485
Short-Term Notes Payable	25,073		—			—			—		—			25,073
Accrued Income Taxes	20,488		13,731			—			—		—			34,219
Borrowings Under Securitization Facility	—		—			—			37,846		—			37,846
Other Accrued Liabilities	135,407		57,074			566,485			9,528		—			768,494
Total Current Liabilities	3,959,472		266,921			(3,022,941		)	312,047		(128,400		)	1,387,099
Long-Term Debt:	3,005,515		46,081			121,523			1,467		—			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		—			2,832,401			—		—			2,832,401
Pneumoconiosis Benefits	—		—			174,781			—		—			174,781
Mine Closing	—		—			446,727			—		—			446,727
Gas Well Closing	—		80,097			68,831			—		—			148,928
Workers’ Compensation	—		—			155,342			306		—			155,648
Salary Retirement	218,004		—			—			—		—			218,004
Reclamation	—		—			47,965			—		—			47,965
Other	101,899		24,518			4,608			—		—			131,025
Total Deferred Credits and Other Liabilities	319,903		104,615			3,730,655			306		—			4,155,479
Total CONSOL Energy Inc. Stockholders’ Equity	3,953,792		5,014,313			5,438,562			154,279		(10,607,154		)	3,953,792
Noncontrolling Interest	—		(47		)	—			—		—			(47		)
Total Liabilities and Equity	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES:

The effective tax rate for the nine months ended September 30, 2013 and 2012 was 809.9% and 20.2%, respectively.

The rate for the nine months ended September 30, 2013 differs from the U.S. federal statutory rate of35% primarily due to a $111,104 income tax charge for excess depletion, $4,701 discrete income tax charge related to the gain on the sale of the Potomac coal reserves, $8,467 discrete income tax charge related to the gain on the sale of the Crowsnest Pass coal reserves, and a $1,585 income tax benefit due to a refund claim related to prior year Commonwealth of Pennsylvania taxes.

For the three months ended September 30, 2013, CONSOL Energy recognized additional tax expense as a result of changes in estimates of percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision. The result of these changes was a tax increase of $5,875.

The rate for the nine months ended September 30, 2012 differs from the U.S. federal statutory rate of 35% primarily due to a $53,932 benefit recorded for excess depletion, $48,976discrete income tax charge related to the gain on the sale of non-producing North Powder River Basin assets, $983discrete income tax reduction related to a successful resolution with the Internal Revenue Service Appeals Division of the company’s Extraterritorial Income Exclusion refund claims for tax years 2004 and 2005, and $1,786discrete income tax reduction related to the successful resolution of an audit with the Canadian Revenue Agency.

For the three months ended September 30, 2012, CONSOL Energy recognized additional tax expense as a result of changes in estimates of percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision. The result of these changes was a tax increase of $6,004.

The total amounts of uncertain tax positions at September 30, 2013 and 2012 were $22,770 and $25,570, respectively. If these uncertain tax positions were recognized, approximately $2,071 and $3,891, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the nine months ended September 30, 2013 and 2012.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of September 30, 2013 and 2012, the Company reported an accrued interest liability relating to uncertain tax positions of $5,851 and $7,095, respectively. The accrued interest liability includes $1,020 and $1,722 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2013 and 2012, respectively.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of September 30, 2013 and 2012, 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.

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Financial Instruments Measured at Fair Value on a Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Gas Cash Flow hedges	$ 0	$ 0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Gas Cash Flow hedges	102,114	128,945
Significant Unobservable Inputs (Level 3)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Gas Cash Flow hedges	$ 0	$ 0

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Collaborative Arrangement Disclosure [Text Block]

The following table provides information about our industry participation agreements as of September 30, 2013:

Shale Play	Industry Participation Agreement Partner	Industry Participation Agreement Date	Drilling Carries Remaining*
Marcellus	Noble Energy, Inc.	September 30, 2011	$	1,885,785
Utica	Hess Ohio Developments, LLC	October 21, 2011	$	255,148

Property, Plant and Equipment

	September 30, 2013		December 31, 2012
Coal and other plant and equipment	$	6,207,105	$	6,030,620
Intangible drilling cost	1,830,666		1,550,297
Proven gas properties	1,601,106		1,596,838
Coal properties and surface lands	1,449,526		1,346,151
Unproven gas properties	1,383,921		1,266,017
Gas gathering equipment	1,046,495		1,006,882
Airshafts	746,134		706,388
Mine development	608,630		537,939
Leased coal lands	529,409		529,758
Gas wells and related equipment	623,176		492,367
Coal advance mining royalties	397,015		391,501
Other gas assets	125,635		82,217
Gas advance royalties	22,286		8,229
Total Property Plant and Equipment	16,571,104		15,545,204
Less: Accumulated DD&A	5,940,247		5,354,237
Total Net PP&E	$	10,630,857	$	10,190,967

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Basis of Presentation Reclassification of adjustments out of Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Natural Gas Swaps	$ (38,379)	$ (77,492)	$ (93,146)	$ (251,357)
Tax Benefit of Natural Gas Swaps	14,025	29,683	36,551	97,760
Natural Gas Swaps, Net of Tax	(24,354)	(47,809)	(56,595)	(153,597)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(8,212)	(13,915)	(24,635)	(39,937)
Defined Benefit Plan, Amortization of Gains (Losses)	21,055	26,611	69,802	79,688
Other Comprehensive Income (Loss), Finalization of Pension and Non-Pension Postretirement Plan Valuation, Net of Tax	6,296		(38,498)
Defined Benefit Plan, Net Periodic Benefit Cost	19,139	12,696	83,665	39,751
Tax Expense on Actuarially Determined Long-Term Liabilities	7,306	4,775	(31,936)	(14,946)
Actuarially Determined Long-Term Liability Adjustments, Net of Tax	11,833	7,921	51,729	24,805
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(408)	(408)	(1,223)	(1,223)
Defined Benefit Plan, Amortization of Gains (Losses)	(8,042)	(11,959)	(30,764)	(35,876)
Other Comprehensive Income (Loss), Finalization of Pension and Non-Pension Postretirement Plan Valuation, Net of Tax	6,296	0	38,498	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ 14,988	$ 14,936	$ 73,281	$ 43,756

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT:

	September 30, 2013		December 31, 2012
Coal and other plant and equipment	$	6,207,105	$	6,030,620
Intangible drilling cost	1,830,666		1,550,297
Proven gas properties	1,601,106		1,596,838
Coal properties and surface lands	1,449,526		1,346,151
Unproven gas properties	1,383,921		1,266,017
Gas gathering equipment	1,046,495		1,006,882
Airshafts	746,134		706,388
Mine development	608,630		537,939
Leased coal lands	529,409		529,758
Gas wells and related equipment	623,176		492,367
Coal advance mining royalties	397,015		391,501
Other gas assets	125,635		82,217
Gas advance royalties	22,286		8,229
Total Property Plant and Equipment	16,571,104		15,545,204
Less: Accumulated DD&A	5,940,247		5,354,237
Total Net PP&E	$	10,630,857	$	10,190,967

Industry Participation Agreements

CONSOL Energy has two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for our retained interests.

On October 21, 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which were net of $5,719 in 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 aggregate amount of the drilling carry can be adjusted downward under provisions of the joint venture agreements in certain events. The net gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. CONSOL Energy and Hess have agreed to focus their development efforts on six core counties in southeastern Ohio, in which the joint venture holds approximately 73,000 mostly fee acres. To this end, the parties have agreed to pursue the sale of approximately 63,000 acres outside of the focus areas. In addition, as previously announced, based on title work performed by Hess as part of the title defect process, we believe that there are chain of title issues with respect to approximately 39,000 of the joint venture acres representing approximately $153,000 of carry, most of which likely cannot be cured. These acres, together with another 26,000 acres of allegedly defective acres will be reassigned to CONSOL Energy. CONSOL Energy may elect to cure the alleged defects related to these acres and develop them, or sell the acres for its own account. After taking into account the reassignment of approximately 65,000 acres, the parties have agreed that the total carry remaining after these adjustments is $335,000. The loss of these Utica Shale acres will not have a material impact on the Company's financial statements.  

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 September 2013, cash proceeds of $327,964 were received related to the second anniversary note receivable. In September 2012, cash proceeds of $327,964 were received related to the first anniversary note receivable. During December 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. Adjusted cash proceeds of $15,598 related to the additional receivable were received in April 2012. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 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 is currently suspended and 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 aggregate amount of the drilling carry may also be adjusted downward under provisions of the joint venture agreements in certain events.

Under our joint venture agreement with Noble, Noble had the right to perform due diligence on the title to the oil and gas interests which CONSOL Energy conveyed to them and to assert that title to the acreage is defective. CONSOL Energy then can review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party can submit the defect to an arbitrator for resolution. The Company has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, the Company has addressed defects with respect to approximately 86.498 gross deal acres, having a carry value of approximately $543,000, to the satisfaction of both parties. Noble has asserted title defects with respect to approximately 2,868 gross deal acres, having a carry value of approximately $27,000, which have not yet been addressed to the full satisfaction of both parties. The Company is working closely with Noble to address these remaining and final alleged defects. To date, the Company has conceded defects which have an aggregate value of approximately $204,000 in excess of the applicable deductibles. The impact of these conceded defects was $12,983 and $21,763 of expense for the three and nine months ended September 30, 2013 and was included in Cost of Goods Sold and Other Charges in the Consolidated Statement of Income. CONSOL Energy and Noble made a concerted effort during the quarter to address the remaining title defects, which resulted in a higher write-off of defected acres than in prior quarters; however, as a result of this effort, the parties have resolved substantially all outstanding asserted defects and any final write-off in the fourth quarter is not expected to be material.

The following table provides information about our industry participation agreements as of September 30, 2013:

Shale Play	Industry Participation Agreement Partner	Industry Participation Agreement Date	Drilling Carries Remaining*
Marcellus	Noble Energy, Inc.	September 30, 2011	$	1,885,785
Utica	Hess Ohio Developments, LLC	October 21, 2011	$	255,148

*See above for a description of the impact on the drilling carries of title defects that have been asserted by Noble.

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CWP and Workers Comp - Net Periodic Costs

9 Months Ended

Sep. 30, 2013

CWP And Workers Comp Net Periodic Cost [Abstract]

Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation:

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

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

	CWP												Workers' Compensation
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2,135		$	1,927		$	6,405		$	5,783		$	3,533		$	3,634		$	10,599		$	10,903
Interest cost	1,808			1,991			5,424			5,973			1,655			1,778			4,966			5,335
Amortization of actuarial gain	(4,213		)	(4,933		)	(12,638		)	(14,799		)	(699		)	(986		)	(2,098		)	(2,958		)
State administrative fees and insurance bond premiums	—			—			—			—			1,496			1,795			4,500			5,340
Legal and administrative costs	—			—			—			—			591			648			1,773			1,943
Net periodic (benefit) cost	$	(270	)	$	(1,015	)	$	(809	)	$	(3,043	)	$	6,576		$	6,869		$	19,740		$	20,563

CONSOL Energy does not expect to contribute to the CWP plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $7,879 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2013. We intend to pay benefit claims as they become due. For the nine months ended September 30, 2013, $21,271 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

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Consolidated Statements of Stockholders' Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock [Member]	Capital in Excess of Par Value	Retained Earnings (Deficit)	Accumulated Other Comprehensive Income (Loss)	Common Stock in Treasury	Total CONSOL Energy Inc. Stockholders' Equity	Non-Controlling Interest
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012	$ 3,953,745	$ 2,284	$ 2,296,908	$ 2,402,551	$ (747,342)	$ (609)	$ 3,953,792	$ (47)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	(77,741)	0	0	(77,741)	0	0	(77,741)	(942)
Net Income (Loss)	(78,683)
Other Comprehensive Income (Loss), Net of Tax	97,446	0	0	0	97,446	0	97,446	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	18,763	0	0	(77,741)	97,446	0	19,705	(942)
Proceeds from Issuance of Common Stock	2,698	8	2,690	0	0	0	2,698	0
Stock Issued During Period, Value, Treasury Stock Reissued	(9,194)	0	0	(9,803)	0	609	(9,194)	0
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation	(2,539)	0	(2,539)	0	0	0	(2,539)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	50,914	0	50,914	0	0	0	50,914	0
Dividends, Cash	(57,211)	0	0	(57,211)	0	0	(57,211)	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2013	$ 3,957,176	$ 2,292	$ 2,347,973	$ 2,257,796	$ (649,896)	$ 0	$ 3,958,165	$ (989)

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Accounts Receivable Securitization (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 AR securitization facility [Member]	Sep. 30, 2012 AR securitization facility [Member]	Sep. 30, 2013 AR securitization facility [Member]	Sep. 30, 2012 AR securitization facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity			$ 200,000		$ 200,000
Current borrowing capacity of receivable facility			200,000		200,000
Letters of credit amount outstanding			155,636		155,636
Costs associated with the receivables facility			416	420	1,328	1,276
Expiration date of receivables facility					Mar. 30, 2017
Accounts Receivable - Securitized	44,364	37,846
Increase (Decrease) in Accounts Receivable from Securitization	$ 6,518

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Income Taxes Income Tax Reconciliation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
Amount
Income Tax Reconciliation, Nondeductible Expense, Depletion		$ 111,104	$ 53,932
Percent
Statutory U.S. Federal Income Tax Rate		35.00%
Income Tax Expense / Effective Rate		809.90%	20.20%
Unusual or Infrequent, Tax Effect	$ 8,467	$ 4,701

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

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:

	For the Three Months Ended September 30,
	2013		2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	71,674	$	132,731
Gain/(Loss) recognized in Accumulated OCI	$	13,246	$	(6,459	)
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	24,354	$	47,809
Ending Balance – Accumulated OCI	$	60,566	$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	2,592	$	1,732

	For the Nine Months Ended September 30,
	2013			2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	76,761		$	151,780
Gain/(Loss) recognized in Accumulated OCI	$	40,400		$	80,280
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	56,595		$	153,597
Ending Balance – Accumulated OCI	$	60,566		$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(120	)	$	1,778

There were no amounts excluded from the assessment of hedge effectiveness in 2013 or 2012.

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Reconciliation of Segment Information, Total Assets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
Assets:
Assets	$ 12,737,072	$ 12,670,909	$ 12,556,594
Total Reportable Business Segments
Assets:
Assets	11,787,041		11,465,377
Coal
Assets:
Assets	5,792,969		5,594,926
Gas
Assets:
Assets	5,994,072		5,870,451
All Other Segments [Member]
Assets:
Assets	356,848		376,400
Excludes Gas Segment [Member]
Items excluded from segment assets:
Cash and Other Investments	17,988		40,331
Intersegment Elimination [Member]
Assets:
Assets	593,183		714,817
Items excluded from segment assets:
Recoverable Income Taxes	0		12,132
Deferred Tax Assets	538,930		618,742
Bond Issuance Costs	$ 36,265		$ 43,612

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Costs Related to Purchase Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Schedule of Costs Related to Purchase Obligations [Line Items]
Total costs related to purchase obligations	$ 64,940	$ 105,808	$ 228,186	$ 240,375
Major equipment purchases
Schedule of Costs Related to Purchase Obligations [Line Items]
Total costs related to purchase obligations	8,990	59,799	57,571	104,980
Firm transportation expense
Schedule of Costs Related to Purchase Obligations [Line Items]
Total costs related to purchase obligations	29,654	18,844	89,196	49,711
Gas drilling obligations
Schedule of Costs Related to Purchase Obligations [Line Items]
Total costs related to purchase obligations	26,296	27,100	81,419	85,192
Other Obligations
Schedule of Costs Related to Purchase Obligations [Line Items]
Total costs related to purchase obligations	$ 0	$ 65	$ 0	$ 492

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Commitments and Contingencies

3 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 amounts 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 $792,000.

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. The AOC was signed on July 20, 2012, and as a result, the EPA granted 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%. In 2011, CONSOL Energy established an initial accrual based on its allocated share of the costs among the viable former customers of American Electric Corp. During the year ended December 31, 2012, CONSOL Energy funded $250 to an independent trust established for the remediation, which is 50% of CONSOL Energy's allocated share of the trust fund. The liability is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the 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 and in September 2008, the EPA notified CONSOL Energy and 60 other companies that they are PRPs for these additional areas. 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 $12,800. CONSOL Energy recognized $576 in expense in Cost of Goods Sold and Other charges in the nine months ended September 30, 2013 and recognized no expense in the nine months ended September 30, 2012. Also, CONSOL Energy has provided funding to an independent trust established for this remediation. CONSOL Energy funded $2,563 in the nine months ended September 30, 2013 and funded $400 in the nine months ended September 30, 2012. As of September 30, 2013, 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 $3,805. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at September 30, 2013 is $1,769.

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

South Carolina Electric & Gas Company Arbitration: In April, 2009, South Carolina Electric & Gas Company (SCE&G), a public utility, filed an arbitration complaint, against CONSOL of Kentucky Inc. and CONSOL Energy Sales Company, both wholly owned subsidiaries of CONSOL Energy, seeking $36,000 in damages. SCE&G claimed it suffered those 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, alleging that SCE&G had agreed that shortfalls could be made up in 2009.  A four day hearing on the claims commenced on April 30, 2012. On December 21, 2012, the Arbitration Panel awarded SCE&G $9,735, plus interest at 8.75% from January 9, 2011, and attorney fees. The Award is against CONSOL of Kentucky only. On August 14, 2013, the Panel, over vigorous objection by CONSOL, awarded SCE&G $1,232 for attorneys’ fees and expenses. We had established an accrual to cover our estimated liability for this case, and have paid the final award in the nine months ended September 30, 2013. This matter is now concluded.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company, et. al. The lawsuit alleges that the plaintiff class consists of forced-pooled unleased gas owners whose gas ownership is in conflict, the Virginia Supreme Court and General Assembly have decided that coalbed methane (CBM) belongs to the owner of the gas estate, the Virginia Gas and Oil Act of 1990 unconstitutionally provides only a 1/8 net proceeds royalty to CBM owners for gas produced under the forced-pooled orders, and CNX Gas Company relied upon control of only the coal estate in force pooling the CBM notwithstanding decisions by the Virginia Supreme Court. 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 lawsuit also alleges CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed 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. 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. The Magistrate Judge recommended against the dismissal of certain other claims. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An amended complaint was filed, which added additional allegations that include gas hedging receipts should have been used as the basis for royalty payments, severance tax should not be allowed as a post-production deduction from royalties, and damages incurred because gas was produced prior to the entry of pooling orders. A motion to dismiss the Amended Complaint was filed and denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a Rule 23 class action and intends to appeal the class certification Order to the U.S. Court of Appeals for the Fourth Circuit. Discovery is proceeding in this litigation. CONSOL Energy believes that the case has meritorious defenses 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al.  The lawsuit alleges that the plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit alleges that the Virginia Supreme Court and General Assembly have decided that the plaintiff owns the gas and is entitled to royalties held in escrow by the Commonwealth of Virginia or CNX Gas Company. The lawsuit also alleges 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. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breach of fiduciary duties; and unjust enrichment. The Magistrate Judge issued a Report and Recommendation recommending dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An Amended Complaint was filed which added an additional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and was denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a Rule 23 class action and intends to appeal the class certification Order to the U.S. Court of Appeals for the Fourth Circuit. Discovery is proceeding in this litigation. CONSOL Energy believes that the case has meritorious defenses 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 was included in Other Accrued Liabilities on the Consolidated Balance Sheet.

CNX Gas Shareholders Litigation: CONSOL Energy was named as a defendant in four putative class actions brought by alleged shareholders of CNX Gas Corporation 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 two cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL).  (A third case filed in Delaware was voluntarily dismissed by the plaintiff in 2010.) All four 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. Following a mediation, the parties to the Delaware litigation have agreed in principle to a settlement and release of all of the claims of the plaintiff class (as defined in a January 20, 2011 order of certification) in exchange for defendants' agreement to establish a settlement fund in the amount of $42,730 for distribution to class members, of which CONSOL Energy is responsible for $19,200. On May 8, 2013, the parties executed and filed with the Court a Stipulation and Agreement of Compromise and Settlement. A Settlement Hearing was held by the Court on August 23, 2013, and the settlement was approved. There were no appeals, and the settlement was paid in October 2013.

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

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 Litigation: On March 22, 2012, the Company was served with four complaints filed on May 31, 2011 by four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, subsidiaries of CONSOL Energy, as well as CONSOL Energy itself in the Circuit Court of Russell County, Virginia. The complaints seek damages and injunctive relief in connection with the deposit of water from mining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits allege damage to coal and coalbed methane and seek recovery in tort, contract and assumpsit (quasi-contract). The cases were removed to federal court, motions to dismiss were filed by CCC, and then were voluntarily dismissed by the plaintiffs. On January 30, 2013, the four plaintiffs filed a single consolidated complaint against the same defendants in the United States District Court for the Western District of Virginia, alleging the same damage and theories of recovery for storage of water in the mine voids ostensibly underlying their property. The suit seeks damages ranging from $4,000 to $8,000 plus punitive damages. Service was effected on April 1, 2013 by waiver. A Motion to Dismiss Plaintiffs' Complaint and, in the Alternative, Motion for More Definitive Statement was filed by the defendants on May 31, 2013. Plaintiffs' Response in opposition to the Motion to Dismiss was filed on June 20, 2013, and the defendants on July 1, 2013, filed their Reply to the Response. Plaintiffs filed a Sur Reply brief on July 8, 2013, for the first time arguing the interpretation of the Virginia Mine Void Statute urged by defendants was unconstitutional. Based on Plaintiffs’ challenge, the Court on August 1, 2013, entered a Certificate pursuant to 28 USC Section 2304 notifying the Virginia Attorney General that the Mine Void Statute had been called into question and advising the Commonwealth of its right to intervene in the proceedings for the limited purpose of addressing the constitutionality of the statute. To date, the Virginia Attorney General has not responded. CONSOL Energy intends to vigorously defend the suit.

Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court.  The named plaintiff is Earl D. Hall.  The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy.  The complaint alleges more than 1,000 similarly situated lessors.  The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying royalties on oil production. The complaint also alleges that royalty statements were false and misleading.  The complaint seeks damages, interest and an accounting on a well-by-well basis. The case has been inactive since December 2011. 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 ruled for CNX Gas Company and CONSOL Energy, holding that the “roof/rider” coal is included in the Pittsburgh 8 coal seam. The plaintiffs have indicated that they intend to appeal that decision. A trial on the issue of whether a drilling that deviates from the coal seam results in damage to the gas owner is anticipated for first quarter 2014. 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 Inc., 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 farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources 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 Resources' 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/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently been permitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A motion to dismiss will be filed. Initial mediation efforts have been unsuccessful. A Status Conference and hearing on pending discovery motions has been scheduled by the Court for November 6, 2013. 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. Discovery is proceeding in this litigation. 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. (Comer I). 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 (Comer II). The trial court dismissed this case, and the dismissal was appealed. On May 14, 2013, a panel of the U.S. Court of Appeals for the Fifth Circuit affirmed, holding res judicata arising from Comer I bars the plaintiffs' claims in Comer II. On June 5, 2013, the Fifth Circuit issued its mandate. August 12, 2013, was the deadline by which Plaintiffs had to file a certiorari petition with the Supreme Court of the United States. They did not do so. This matter is now concluded.

At September 30, 2013, 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	$	190,358	$	71,624	$	118,734	$	—	$	—
Environmental	56,294		54,566		1,728		—		—
Other	83,246		34,488		48,758		—		—
Total Letters of Credit	329,898		160,678		169,220		—		—
Surety Bonds:
Employee-Related	204,884		204,884		—		—		—
Environmental	537,167		495,017		42,150		—		—
Other	31,955		31,719		235		—		1
Total Surety Bonds	774,006		731,620		42,385		—		1
Total Commitments	$	1,103,904	$	892,298	$	211,605	$	—	$	1

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state and federal 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 September 30, 2013, the purchase obligations for each of the next five years and beyond were as follows:

Obligations Due	Amount
Less than 1 year	$	393,709
1 - 3 years	253,025
3 - 5 years	189,138
More than 5 years	419,240
Total Purchase Obligations	$	1,255,112

Costs related to these purchase obligations include:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Major equipment purchases	$	8,990	$	59,799	$	57,571	$	104,980
Firm transportation expense	29,654		18,844		89,196		49,711
Gas drilling obligations	26,296		27,100		81,419		85,192
Other	—		65		—		492
Total costs related to purchase obligations	$	64,940	$	105,808	$	228,186	$	240,375

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Accounts Receivable Securitization

9 Months Ended

Sep. 30, 2013

ACCOUNTS RECEIVABLE SECURITIZATION: [Abstract]

Accounts Receivable Securitization

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 September 30, 2013, there were letters of credit outstanding against the facility of $155,636. CONSOL Energy management believes that these letters of credit will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's 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 or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $416 and $1,328 for three and nine months ended September 30, 2013, respectively. Costs associated with the receivables facility totaled $420 and $1,276 for three and nine months ended September 30, 2012, 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 September 30, 2013 and December 31, 2012, eligible accounts receivable totaled $200,000. There was no subordinated retained interest at September 30, 2013 and at December 31, 2012. There were $44,364 of borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of September 30, 2013 and $37,846 at December 31, 2012. The accounts receivable securitization program increased $6,518 in the nine months ended September 30, 2013 and there was no change in the nine months ended September 30, 2012. The increase is reflected in the Net Cash Used in Financing Activities in the Consolidated Statement of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

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Guarantor Subsidiaries Income Statement (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	$ 1,160,114	$ 1,084,041	$ 3,512,055	$ 3,584,805
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Sales-Purchased Gas	1,608	953	4,372	2,443
Freight-Outside	11,563	27,430	35,749	126,195
Other Income (including equity earnings)	42,627	34,697	138,824	293,196
Total Revenue and Other Income	1,231,418	1,160,089	3,737,738	4,041,346
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	851,088	827,530	2,639,929	2,588,460
Gas Royalty Interests Costs	12,864	10,543	38,204	27,916
Purchased Gas Costs	941	737	2,961	2,123
Related Party Activity	0	0	0	0
Freight Expense	11,563	27,430	35,749	126,195
Selling, General and Administrative Expenses	33,472	36,681	104,265	109,412
Depreciation, Depletion and Amortization	169,152	153,877	489,774	463,048
Interest Expense	56,301	54,075	164,197	168,788
Taxes Other Than Income	85,463	80,587	251,575	256,543
Total Costs	1,220,844	1,191,460	3,726,654	3,742,485
Earnings Before Income Taxes	10,574	(31,371)	11,084	298,861
Income Tax Expense (Benefit)	74,623	(19,898)	89,767	60,428
Net Income (Loss) Attributable to Noncontrolling Interest	398	105	942	134
Net Income (Loss) Available to Common Stockholders, Basic	(63,651)	(11,368)	(77,741)	238,567
Net Income (Loss)	(64,049)	(11,473)	(78,683)	238,433
Parent Issuer [Member]
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	0	0	0	0
Sales-Gas Royalty Interests	0	0	0	0
Sales-Purchased Gas	0	0	0	0
Freight-Outside	0	0	0	0
Other Income (including equity earnings)	78,203	(17,948)	354,386	399,817
Total Revenue and Other Income	78,203	(17,948)	354,386	399,817
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	37,591	18,699	117,830	90,230
Gas Royalty Interests Costs	0	0	0	0
Purchased Gas Costs	0	0	0	0
Related Party Activity	9,710	8,575	32,385	1,575
Freight Expense	0	0	0	0
Selling, General and Administrative Expenses	0	0	0	0
Depreciation, Depletion and Amortization	3,288	3,085	9,735	8,901
Interest Expense	52,165	50,811	153,141	158,505
Taxes Other Than Income	165	(504)	430	159
Total Costs	102,919	80,666	313,521	259,370
Earnings Before Income Taxes	(24,716)	(98,614)	40,865	140,447
Income Tax Expense (Benefit)	38,935	(87,246)	118,606	(98,120)
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	(63,651)	(11,368)	(77,741)	238,567
Net Income (Loss)	(63,651)	(11,368)	(77,741)	238,567
CNX Gas Guarantor [Member]
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	193,381	165,448	534,221	474,574
Sales-Gas Royalty Interests	15,506	12,968	46,738	34,707
Sales-Purchased Gas	1,608	953	4,372	2,443
Freight-Outside	0	0	0	0
Other Income (including equity earnings)	12,596	11,772	37,055	46,177
Total Revenue and Other Income	223,091	191,141	622,386	557,901
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	128,402	96,619	359,397	296,959
Gas Royalty Interests Costs	12,874	10,565	38,235	27,951
Purchased Gas Costs	941	737	2,961	2,123
Related Party Activity	0	0	0	0
Freight Expense	0	0	0	0
Selling, General and Administrative Expenses	11,600	9,906	33,429	29,199
Depreciation, Depletion and Amortization	58,444	52,214	163,079	148,343
Interest Expense	2,578	1,145	6,375	3,554
Taxes Other Than Income	9,847	8,426	25,534	24,790
Total Costs	224,686	179,612	629,010	532,919
Earnings Before Income Taxes	(1,595)	11,529	(6,624)	24,982
Income Tax Expense (Benefit)	(602)	4,433	(2,557)	9,706
Net Income (Loss) Attributable to Noncontrolling Interest	398	105	942	134
Net Income (Loss) Available to Common Stockholders, Basic	(595)	7,201	(3,125)	15,410
Net Income (Loss)	(993)	7,096	(4,067)	15,276
Other Guarantors Subsidiaries [Member]
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	911,732	861,009	2,813,430	2,919,814
Sales-Gas Royalty Interests	0	0	0	0
Sales-Purchased Gas	0	0	0	0
Freight-Outside	11,563	27,430	35,749	126,195
Other Income (including equity earnings)	25,103	170,877	86,064	230,930
Total Revenue and Other Income	948,398	1,059,316	2,935,243	3,276,939
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	620,652	647,158	1,971,483	1,992,371
Gas Royalty Interests Costs	0	0	0	0
Purchased Gas Costs	0	0	0	0
Related Party Activity	(29,271)	(18,962)	(87,620)	5,078
Freight Expense	11,563	27,430	35,749	126,195
Selling, General and Administrative Expenses	21,582	26,412	69,887	79,169
Depreciation, Depletion and Amortization	106,910	98,060	315,468	304,245
Interest Expense	1,548	2,267	4,871	7,056
Taxes Other Than Income	74,730	71,985	223,254	229,381
Total Costs	807,714	854,350	2,533,092	2,743,495
Earnings Before Income Taxes	140,684	204,966	402,151	533,444
Income Tax Expense (Benefit)	37,143	61,424	(22,740)	143,001
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	103,541	143,542	424,891	390,443
Net Income (Loss)	103,541	143,542	424,891	390,443
Non-Guarantors [Member]
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	54,174	58,405	161,837	192,212
Sales-Gas Royalty Interests	0	0	0	0
Sales-Purchased Gas	0	0	0	0
Freight-Outside	0	0	0	0
Other Income (including equity earnings)	4,928	4,917	15,705	16,089
Total Revenue and Other Income	59,102	63,322	177,542	208,301
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	54,857	57,408	162,050	186,635
Gas Royalty Interests Costs	0	0	0	0
Purchased Gas Costs	0	0	0	0
Related Party Activity	458	427	1,298	1,376
Freight Expense	0	0	0	0
Selling, General and Administrative Expenses	290	363	949	1,044
Depreciation, Depletion and Amortization	510	518	1,492	1,559
Interest Expense	13	11	34	33
Taxes Other Than Income	721	680	2,357	2,213
Total Costs	56,849	59,407	168,180	192,860
Earnings Before Income Taxes	2,253	3,915	9,362	15,441
Income Tax Expense (Benefit)	(853)	1,491	(3,542)	5,841
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	3,106	2,424	12,904	9,600
Net Income (Loss)	3,106	2,424	12,904	9,600
Consolidation, Eliminations [Member]
Schedule of Condensed Consolidating Statement of Operations [Line Items]
Sales-Outside	827	(821)	2,567	(1,795)
Sales-Gas Royalty Interests	0	0	0	0
Sales-Purchased Gas	0	0	0	0
Freight-Outside	0	0	0	0
Other Income (including equity earnings)	(78,203)	(134,921)	(354,386)	(399,817)
Total Revenue and Other Income	(77,376)	(135,742)	(351,819)	(401,612)
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	9,586	7,646	29,169	22,265
Gas Royalty Interests Costs	(10)	(22)	(31)	(35)
Purchased Gas Costs	0	0	0	0
Related Party Activity	19,103	9,960	53,937	(8,029)
Freight Expense	0	0	0	0
Selling, General and Administrative Expenses	0	0	0	0
Depreciation, Depletion and Amortization	0	0	0	0
Interest Expense	(3)	(159)	(224)	(360)
Taxes Other Than Income	0	0	0	0
Total Costs	28,676	17,425	82,851	13,841
Earnings Before Income Taxes	(106,052)	(153,167)	(434,670)	(415,453)
Income Tax Expense (Benefit)	0	0	0	0
Net Income (Loss) Attributable to Noncontrolling Interest	0	0	0	0
Net Income (Loss) Available to Common Stockholders, Basic	(106,052)	(153,167)	(434,670)	(415,453)
Net Income (Loss)	$ (106,052)	$ (153,167)	$ (434,670)	$ (415,453)

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

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 thermal 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 nine months ended September 30, 2013, 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 nine months ended September 30, 2013, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the nine months ended September 30, 2013, 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.

Annually, the preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2012 gas reserve results, which are reported in the Supplemental Gas Data year ended December 31, 2012 Form 10-K, were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer in the state of Texas with over 14 years of experience in the oil and gas industry.

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Derivative Instruments

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments:

DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. 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 the fair value of the derivatives are reported in Other Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets and reclassified into Outside Sales on the Consolidated Statements of Income 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.

None of our counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL Energy would have to post collateral for hedges in a liabilities position in excess of defined thresholds. All of our derivative instruments are subject to master netting arrangements with our counterparties.  CONSOL Energy recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis.

                Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CONSOL Energy and the applicable counterparty would net settle all open hedge positions.

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of September 30, 2013, the total notional amount of the Company’s outstanding natural gas swap contracts was 216.5 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $44,438 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Outside Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at September 30, 2013 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $107,366 and a liability of $5,252. The total asset is comprised of $75,735 and $31,631 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $746 and $4,506 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The gross fair value at December 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $135,969 and a liability of $7,024. The total asset is comprised of $80,057 and $55,912 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $970 and $6,054 which were included in Other Accrued Liabilities and Other Liabilities, 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:

	For the Three Months Ended September 30,
	2013		2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	71,674	$	132,731
Gain/(Loss) recognized in Accumulated OCI	$	13,246	$	(6,459	)
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	24,354	$	47,809
Ending Balance – Accumulated OCI	$	60,566	$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	2,592	$	1,732

	For the Nine Months Ended September 30,
	2013			2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	76,761		$	151,780
Gain/(Loss) recognized in Accumulated OCI	$	40,400		$	80,280
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	56,595		$	153,597
Ending Balance – Accumulated OCI	$	60,566		$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(120	)	$	1,778

There were no amounts excluded from the assessment of hedge effectiveness in 2013 or 2012.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 21, 2013
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Entity Registrant Name	CONSOL Energy Inc
Entity Central Index Key	0001070412
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		228,941,697

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2013

Notes to Financial Statements [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS:

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

	Fair Value Measurements at September 30, 2013						Fair Value Measurements at December 31, 2012
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	$	—	$	102,114	$	—	$	—	$	128,945	$	—

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

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

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

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

Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair 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:

	September 30, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	21,086		$	21,086		$	21,878		$	21,878
Restricted Cash (a)	$	12,263		$	12,263		$	68,673		$	68,673
Short-Term Notes Payable	$	(47,000	)	$	(47,000	)	$	(25,073	)	$	(25,073	)
Borrowings Under Securitization Facility	$	(44,364	)	$	(44,364	)	$	(37,846	)	$	(37,846	)
Long-Term Debt	$	(3,128,361	)	$	(3,320,618	)	$	(3,129,017	)	$	(3,378,058	)

(a) The 2013 restricted cash balance of $12,263 was included in current assets of the Consolidated Balance Sheet. The 2012 restricted cash balance includes $48,294 and $20,379 included in current assets and other assets of the Consolidated Balance Sheet, respectively.

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The Effect of Derivative Instruments on the Consolidated Statement of Income (Details) (Price Swaps, Derivative in Cash Flow Hedging Relationship, Natural Gas, USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	$ 60,566	$ 78,463	$ 60,566	$ 78,463	$ 71,674	$ 76,761	$ 132,731	$ 151,780
Amount of Gain (Loss) Recognized in OCI on Derivative	13,246	(6,459)	40,400	80,280
Outside Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from Accumulated OCI into Income	24,354	47,809	56,595	153,597
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ 2,592	$ 1,732	$ (120)	$ 1,778

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Derivative Instruments (Details) (Cash Flow Hedging [Member], Price Swaps, Natural Gas, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2013 MMcf	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Notional Amount of Outstanding Natural Gas Forward Contracts (in MMcf)	216,500,000
Unrealized Gain Expected to be Reclassified from Other Comprehensive Income and into Earnings During the Next Twelve Months	$ 44,438
Derivative Assets Designated as Hedging Instruments	107,366	135,969
Derivative Liabilities Designated as Hedging Instruments	5,252	7,024
Prepaid Expenses
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Assets, Current	75,735	80,057
Other Assets
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Assets, Noncurrent	31,631	55,912
Other Accrued Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Assets, Current	746	970
Other Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Liabilities, Noncurrent	$ 4,506	$ 6,054