UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended ~~June~~September 30, 2013



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of ~~July 18,~~October 21, 2013
Common stock, $0.01 par value		~~228,848,942~~228,941,697

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012	3
	Consolidated Statements of Comprehensive Income for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and 2012	4
	Consolidated Balance Sheets at ~~June~~September 30, 2013 and December 31, 2012	5
	Consolidated ~~Statement~~Statements of Stockholders’ Equity for the ~~six~~nine months ended ~~June~~September 30, 2013	7
	Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~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	8890

ITEM 4.	Controls and Procedures	9092

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	9193

ITEM 4.	Mine Safety Disclosures	9193

ITEM 6.	Exhibits	9193

PART I

FINANCIAL INFORMATION


ITEM 1.	CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(Dollars in thousands, except per share data)


	Three Months Ended					Six Months Ended					Three Months Ended						Nine Months Ended
	June 30,					June 30,					September 30,						September 30,
	2013			2012		2013			2012		2013			2012			2013			2012
Sales—Outside	$	1,125,776		$	1,189,293	$	2,351,941		$	2,500,764	$	1,160,114		$	1,084,041		$	3,512,055		$	3,584,805
Sales—Gas Royalty Interests	17,028			9,533		31,232			21,739		15,506			12,968			46,738			34,707
Sales—Purchased Gas	1,406			651		2,764			1,490		1,608			953			4,372			2,443
Freight—Outside	10,125			49,472		24,186			98,765		11,563			27,430			35,749			126,195
Other Income	62,345			205,538		96,197			258,499		42,627			34,697			138,824			293,196
Total Revenue and Other Income	1,216,680			1,454,487		2,506,320			2,881,257		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)	855,878			856,889		1,788,841			1,760,930		851,088			827,530			2,639,929			2,588,460
Gas Royalty Interests Costs	13,534			7,124		25,340			17,373		12,864			10,543			38,204			27,916
Purchased Gas Costs	1,061			869		2,020			1,386		941			737			2,961			2,123
Freight Expense	10,125			49,472		24,186			98,765		11,563			27,430			35,749			126,195
Selling, General and Administrative Expenses	37,123			33,732		70,793			72,731		33,472			36,681			104,265			109,412
Depreciation, Depletion and Amortization	159,307			153,824		320,622			309,171		169,152			153,877			489,774			463,048
Interest Expense	54,518			56,593		107,896			114,713		56,301			54,075			164,197			168,788
Taxes Other Than Income	83,325			84,329		166,112			175,956		85,463			80,587			251,575			256,543
Total Costs	1,214,871			1,242,832		2,505,810			2,551,025		1,220,844			1,191,460			3,726,654			3,742,485
Earnings Before Income Taxes	1,809			211,655		510			330,232
Earnings (Loss) Before Income Taxes											10,574			(31,371		)	11,084			298,861
Income Taxes	14,622			58,945		15,144			80,326		74,623			(19,898		)	89,767			60,428
Net (Loss) Income	(12,813		)	152,710		(14,634		)	249,906		(64,049		)	(11,473		)	(78,683		)	238,433
Add: Net Loss Attributable to Noncontrolling Interest	287			29		544			29		398			105			942			134
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	152,739	$	(14,090	)	$	249,935	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Earnings Per Share:
Basic	$	(0.05	)	$	0.67	$	(0.06	)	$	1.10	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.05	)	$	0.67	$	(0.06	)	$	1.09	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.04
Weighted Average Number of Common Shares Outstanding:
Basic	228,721,980			227,548,394		228,520,886			227,408,832		228,876,336			227,654,395			228,640,671			227,491,284
Dilutive	228,721,980			229,252,185		228,520,886			229,122,594		228,876,336			227,654,395			228,640,671			229,191,870
Dividends Paid Per Share	$	0.125		$	0.125	$	0.125		$	0.250	$	0.125		$	0.125		$	0.250		$	0.375

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)

Three Months Ended Six Months Ended
June 30, June 30,
2013 2012 2013 2012
Net (Loss) Income $ (12,813 ) $ 152,710
$ (14,634 ) $ 249,906
Other Comprehensive Income (Loss):
  Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($26,489), ($4,570), ($54,739), ($40,467)) 42,904
7,586
88,661
67,159
  Net Increase in the Value of Cash Flow Hedges (Net of tax: ($31,466), ($6,869), ($17,500), ($55,877)) 45,749
10,663
27,154
86,739
  Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $10,542, $36,697, $22,526, $68,077) (9,528 ) (57,847 ) (32,241 ) (105,788 )

Other Comprehensive Income (Loss) 79,125
(39,598 ) 83,574
48,110

Comprehensive Income 66,312
113,112
68,940
298,016

Add: Comprehensive Loss Attributable to Noncontrolling Interest 287
29
544
29

Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders $ 66,599
$ 113,141
$ 69,484
$ 298,045



	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.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)


	(Unaudited)				(Unaudited)
	June 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and Cash Equivalents	$	71,938	$	21,878	$	21,086	$	21,878
Accounts and Notes Receivable:
Trade	347,367		428,328		436,388		428,328
Notes Receivables	350,977		318,387		25,813		318,387
Other Receivables	151,269		131,131		160,931		131,131
Accounts Receivable - Securitized	40,719		37,846		44,364		37,846
Inventories	227,994		247,766		238,348		247,766
Deferred Income Taxes	143,004		148,104		81,825		148,104
Recoverable Income Taxes	1,930		—
Restricted Cash	—		48,294		12,263		48,294
Prepaid Expenses	137,643		157,360		162,418		157,360
Total Current Assets	1,472,841		1,539,094		1,183,436		1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	16,194,251		15,545,204		16,571,104		15,545,204
Less—Accumulated Depreciation, Depletion and Amortization	5,770,506		5,354,237		5,940,247		5,354,237
Total Property, Plant and Equipment—Net	10,423,745		10,190,967		10,630,857		10,190,967
Other Assets:
Deferred Income Taxes	388,703		444,585		457,105		444,585
Restricted Cash	—		20,379		—		20,379
Investment in Affiliates	256,097		222,830		261,218		222,830
Notes Receivable	1,512		25,977		155		25,977
Other	210,030		227,077		204,301		227,077
Total Other Assets	856,342		940,848		922,779		940,848
TOTAL ASSETS	$	12,752,928	$	12,670,909	$	12,737,072	$	12,670,909

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)


	(Unaudited)						(Unaudited)
	June 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	461,415		$	507,982		$	512,182		$	507,982
Current Portion of Long-Term Debt	13,422			13,485			13,182			13,485
Short-Term Notes Payable	173,000			25,073			47,000			25,073
Accrued Income Taxes	—			34,219			87,965			34,219
Borrowings Under Securitization Facility	40,719			37,846			44,364			37,846
Other Accrued Liabilities	798,645			768,494			868,904			768,494
Total Current Liabilities	1,487,201			1,387,099			1,573,597			1,387,099
Long-Term Debt:
Long-Term Debt	3,124,000			3,124,473			3,123,755			3,124,473
Capital Lease Obligations	47,750			50,113			48,176			50,113
Total Long-Term Debt	3,171,750			3,174,586			3,171,931			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	2,820,186			2,832,401			2,814,234			2,832,401
Pneumoconiosis Benefits	177,146			174,781			178,508			174,781
Mine Closing	459,392			446,727			460,515			446,727
Gas Well Closing	193,946			148,928			197,093			148,928
Workers’ Compensation	155,518			155,648			156,568			155,648
Salary Retirement	109,691			218,004			74,108			218,004
Reclamation	50,051			47,965			49,487			47,965
Other	102,987			131,025			103,855			131,025
Total Deferred Credits and Other Liabilities	4,068,917			4,155,479			4,034,368			4,155,479
TOTAL LIABILITIES	8,727,868			8,717,164			8,779,896			8,717,164
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,834,765 Issued and 228,800,010 Outstanding at June 30, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012	2,291			2,284
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	2,336,417			2,296,908			2,347,973			2,296,908
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—			—			—
Retained Earnings	2,351,320			2,402,551			2,257,796			2,402,551
Accumulated Other Comprehensive Loss	(663,768		)	(747,342		)	(649,896		)	(747,342		)
Common Stock in Treasury, at Cost—34,755 Shares at June 30, 2013 and 34,755 Shares at December 31, 2012	(609		)	(609		)
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	4,025,651			3,953,792			3,958,165			3,953,792
Noncontrolling Interest	(591		)	(47		)	(989		)	(47		)
TOTAL EQUITY	4,025,060			3,953,745			3,957,176			3,953,745
TOTAL LIABILITIES AND EQUITY	$	12,752,928		$	12,670,909		$	12,737,072		$	12,670,909

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)


	Common Stock		Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity			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		$	2,284	$	2,296,908		$	2,402,551		$	(747,342	)	$	(609	)	$	3,953,792		$	(47	)	$	3,953,745
(Unaudited)
Net Loss	—		—			(14,090		)	—			—			(14,090		)	(544		)	(14,634		)	—		—			(77,741		)	—			—			(77,741		)	(942		)	(78,683		)
Other Comprehensive Income	—		—			—			83,574			—			83,574			—			83,574			—		—			—			97,446			—			97,446			—			97,446
Comprehensive (Loss) Income	—		—			(14,090		)	83,574			—			69,484			(544		)	68,940			—		—			(77,741		)	97,446			—			19,705			(942		)	18,763
Issuance of Common Stock	7		2,490			—			—			—			2,497			—			2,497			8		2,690			—			—			—			2,698			—			2,698
Treasury Stock Activity	—		—			(8,540		)	—			—			(8,540		)	—			(8,540		)	—		—			(9,803		)	—			609			(9,194		)	—			(9,194		)
Tax Cost From Stock-Based Compensation	—		(2,222		)	—			—			—			(2,222		)	—			(2,222		)	—		(2,539		)	—			—			—			(2,539		)	—			(2,539		)
Amortization of Stock-Based Compensation Awards	—		39,241			—			—			—			39,241			—			39,241			—		50,914			—			—			—			50,914			—			50,914
Dividends ($0.125 per share)	—		—			(28,601		)	—			—			(28,601		)	—			(28,601		)
Balance at June 30, 2013	$	2,291	$	2,336,417		$	2,351,320		$	(663,768	)	$	(609	)	$	4,025,651		$	(591	)	$	4,025,060
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.

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)


	Six Months Ended						Nine Months Ended
	June 30,						September 30,
	2013			2012			2013			2012
Operating Activities:
Net (Loss) Income	$	(14,634	)	$	249,906		$	(78,683	)	$	238,433
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	320,622			309,171			489,774			463,048
Stock-Based Compensation	39,241			26,935			50,914			38,423
Gain on Sale of Assets	(32,958		)	(189,981		)	(52,794		)	(190,257		)
Amortization of Mineral Leases	761			3,631			2,014			3,818
Deferred Income Taxes	6,998			30,625			(31,099		)	(5,225		)
Equity in Earnings of Affiliates	(16,667		)	(15,103		)	(20,276		)	(22,676		)
Changes in Operating Assets:
Accounts and Notes Receivable	25,360			40,034			11,145			13,359
Inventories	19,772			(46,726		)	9,418			(8,204		)
Prepaid Expenses	24,433			19,709			(9,259		)	(1,362		)
Changes in Other Assets	24,512			10,604			24,318			(8,961		)
Changes in Operating Liabilities:
Accounts Payable	(13,470		)	(41,266		)	(20,553		)	5,218
Other Operating Liabilities	(6,019		)	(65,693		)	174,740			(11,130		)
Changes in Other Liabilities	2,807			23,456			8,148			1,469
Other	12,636			12,647			31,198			14,210
Net Cash Provided by Operating Activities	393,394			367,949			589,005			530,163
Investing Activities:
Capital Expenditures	(758,000		)	(714,399		)	(1,195,909		)	(1,152,021		)
Change in Restricted Cash	68,673			—			56,410			—
Proceeds from Sales of Assets	240,801			252,229			598,174			583,942
Net Investments In Equity Affiliates	(16,600		)	(21,839		)	(18,112		)	(18,701		)
Net Cash Used in Investing Activities	(465,126		)	(484,009		)	(559,437		)	(586,780		)
Financing Activities:
Proceeds from Short-Term Borrowings	173,000			—			47,000			—
Payments on Miscellaneous Borrowings	(30,162		)	(4,662		)	(32,290		)	(6,565		)
Proceeds from Securitization Facility	2,873			—			6,518			—
Tax Benefit from Stock-Based Compensation	2,185			1,608			2,316			2,578
Dividends Paid	(28,601		)	(56,833		)	(57,211		)	(85,290		)
Issuance of Common Stock	2,497			457			2,698			1,234
Issuance of Treasury Stock	—			109			609			109
Debt Issuance and Financing Fees	—			(148		)	—			(227		)
Net Cash Provided by (Used In) Financing Activities	121,792			(59,469		)
Net Increase (Decrease) in Cash and Cash Equivalents	50,060			(175,529		)
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			21,878			375,736
Cash and Cash Equivalents at End of Period	$	71,938		$	200,207		$	21,086		$	230,958

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and ~~six~~nine months ended ~~June~~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 June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012	2013	2012	2013	2012
Anti-Dilutive Options	4,845,029	2,421,923	4,845,029	2,418,983	4,833,174	5,740,444	4,833,174	2,412,502
Anti-Dilutive Restricted Stock Units	1,383,908	2,642	1,383,908	13,552	1,243,207	1,348,046	1,243,207	13,302
Anti-Dilutive Performance Share Units	83,356	91,340	83,356	91,340	97,142	488,179	97,142	—
Anti-Dilutive Performance Share Options	602,101	501,744	602,101	501,744	602,101	501,744	602,101	501,744
	6,914,394	3,017,649	6,914,394	3,025,619	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 June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012	2013	2012	2013	2012
Options	160,119	39,418	245,113	51,134	11,655	108,477	256,768	159,611
Restricted Stock Units	89,632	64,589	568,141	522,607	130,523	22,025	698,664	548,492
Performance Share Units	—	—	159,228	229,730	—	—	159,228	229,730
	249,751	104,007	972,482	803,471	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 ~~June~~September 30, 2013 and 2012 was $~~9.90~~17.40 and $~~10.26~~7.13, respectively. The weighted average exercise price per share of the options exercised during the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012 was $~~10.16~~10.49 and $~~11.07~~8.39, respectively.

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


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012		2013			2012		2013			2012			2013			2012
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	152,739	$	(14,090	)	$	249,935	$	(63,651	)	$	(11,368	)	$	(77,741	)	$	238,567
Weighted average shares of common stock outstanding:
Basic	228,721,980			227,548,394		228,520,886			227,408,832		228,876,336			227,654,395			228,640,671			227,491,284
Effect of stock-based compensation awards	—			1,703,791		—			1,713,762		—			—			—			1,700,586
Dilutive	228,721,980			229,252,185		228,520,886			229,122,594		228,876,336			227,654,395			228,640,671			229,191,870
Earnings per share:
Basic	$	(0.05	)	$	0.67	$	(0.06	)	$	1.10	$	(0.28	)	$	(0.05	)	$	(0.34	)	$	1.05
Dilutive	$	(0.05	)	$	0.67	$	(0.06	)	$	1.09	$	(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			Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2012	$	76,761		$	(824,103	)	$	(747,342	)	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	27,154			48,766			75,920			40,400			61,912			102,312
Amounts reclassified from accumulated other comprehensive income	(32,241		)	39,895			7,654			(56,595		)	51,729			(4,866		)
New current period other comprehensive income	(5,087		)	88,661			83,574			(16,195		)	113,641			97,446
Balance at June 30, 2013	$	71,674		$	(735,442	)	$	(663,768	)
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 June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Derivative Instruments (Note 12)
Natural gas price swaps	$	(20,070	)	$	(94,544	)	$	(54,767	)	$	(173,865	)	$	(38,379	)	$	(77,492	)	$	(93,146	)	$	(251,357	)
Tax benefit	10,542			36,697			22,526			68,077			14,025			29,683			36,551			97,760
Net of tax	$	(9,528	)	$	(57,847	)	$	(32,241	)	$	(105,788	)	$	(24,354	)	$	(47,809	)	$	(56,595	)	$	(153,597	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(8,211	)	$	(13,915	)	$	(16,423	)	$	(26,021	)	$	(8,212	)	$	(13,915	)	$	(24,635	)	$	(39,937	)
Recognized net actuarial loss	23,559			26,072			48,747			53,077			21,055			26,611			69,802			79,688
Settlement loss	5,087			—			32,202			—			6,296			—			38,498			—
Total	20,435			12,157			64,526			27,056			19,139			12,696			83,665			39,751
Tax expense	(7,800		)	(4,571		)	(24,631		)	(10,173		)	(7,306		)	(4,775		)	(31,936		)	(14,946		)
Net of tax	$	12,635		$	7,586		$	39,895		$	16,883		$	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 ~~six~~nine months ended ~~June~~September 30, 2013 and ~~June~~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.

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.

~~NOTE 2—ACQUISITIONS AND DISPOSITIONS:~~

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 iswas 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 ~~Settlement~~ 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~~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.

OnIn March ~~31,~~ 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 ~~three~~nine months ended ~~June~~September 30, ~~2013.~~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 iswas 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 iswas 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. ~~One payment~~Payment of $25,500 was received in June 2013. A note receivable of $24,500 iswas included in Accounts and Notes Receivables - Notes Receivables in the Consolidated Balance Sheet at ~~June~~September 30, ~~2013.~~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 iswas 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 iswas 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 iswas included in Other Income in the Consolidated Statements of Income for the year ended December 31, 2012.

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

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


	Pension Benefits												Other Postretirement Benefits												Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						June 30,						June 30,						September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	5,581		$	4,850		$	11,287		$	10,003		$	4,849		$	4,566		$	9,698		$	9,766		$	4,897		$	5,527		$	16,184		$	15,530		$	4,849		$	4,525		$	14,547		$	14,291
Interest cost	8,909			9,415			17,752			18,793			29,619			32,795			59,237			68,322			9,497			9,396			27,249			28,190			29,619			33,687			88,856			102,008
Expected return on plan assets	(12,711		)	(11,452		)	(24,855		)	(23,079		)	—			—			—			—			(13,336		)	(11,538		)	(38,191		)	(34,617		)	—			—			—			—
Amortization of prior service cost (credits)	(407		)	(407		)	(815		)	(815		)	(7,804		)	(13,410		)	(15,608		)	(25,009		)
Amortization of prior service credits																									(408		)	(408		)	(1,223		)	(1,223		)	(7,804		)	(13,409		)	(23,411		)	(38,418		)
Recognized net actuarial loss	10,547			11,654			22,722			23,917			17,595			20,020			35,190			40,365			8,042			11,959			30,764			35,876			17,595			20,255			52,784			60,620
Settlement loss	5,087			—			32,202			—			—			—			—			—			6,296			—			38,498			—			—			—			—			—
Net periodic benefit cost	$	17,006		$	14,060		$	58,293		$	28,819		$	44,259		$	43,971		$	88,517		$	93,444		$	14,988		$	14,936		$	73,281		$	43,756		$	44,259		$	45,058		$	132,776		$	138,501

For the ~~six~~nine months ended ~~June~~September 30, 2013, $~~34,376~~55,272 was paid to the pension trust ~~for pension benefits~~ 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. ~~Currently, depending on asset values and asset returns held in the trust, we expect to contribute~~ ~~$50,000~~ ~~to the pension trust in~~ ~~2013~~. 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 ~~six~~three and nine months ended ~~June~~September 30, 2013. Accordingly, CONSOL Energy recognized expense of $~~5,087~~6,296 and $~~32,202~~38,498 for the three and ~~six~~nine months ended ~~June~~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 ~~June~~September 30, 2013 remeasurement resulted in a change to the discount rate to ~~4.84%~~4.80% from ~~4.12%~~4.84% at ~~March 31,~~June 30, 2013. The ~~June~~September remeasurement reduced the pension liability by $~~48,957~~21,264. The ~~June~~September settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $~~33,414~~17,040 in ~~other comprehensive income,~~Other Comprehensive Income, net of $~~20,630~~10,520 in deferred taxes. ~~The March 31, 2013 remeasurement resulted in a change to the discount rate to~~ ~~4.12%~~ ~~from~~ ~~4.00%~~ ~~at December 31, 2012. The March remeasurement reduced the pension liability by~~ ~~$29,916. The March settlement and corresponding remeasurement of the pension plan resulted in an adjustment of~~ ~~$35,261~~ ~~in other comprehensive income, net of~~ ~~$21,770~~ ~~in deferred taxes. Currently, the settlement and remeasurement of the pension plan will result in a~~ ~~$10,960~~ ~~reduction to pension expense compared to what was originally expected to be recognized for the remaining six months of 2013.~~ 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 ~~postretirement~~post-employment benefit plan in 2013. We intend to pay benefit claims as they become due. For the ~~six~~nine months ended ~~June~~September 30, 2013, $~~83,106~~124,504 of other ~~postretirement~~post-employment benefits have been paid.

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

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


	CWP												Workers' Compensation												CWP												Workers' Compensation
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						June 30,						June 30,						September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2,135		$	1,928		$	4,270		$	3,856		$	3,533		$	3,634		$	7,066		$	7,268		$	2,135		$	1,927		$	6,405		$	5,783		$	3,533		$	3,634		$	10,599		$	10,903
Interest cost	1,808			1,991			3,616			3,982			1,655			1,778			3,310			3,556			1,808			1,991			5,424			5,973			1,655			1,778			4,966			5,335
Amortization of actuarial gain	(4,212		)	(4,933		)	(8,425		)	(9,867		)	(699		)	(986		)	(1,398		)	(1,972		)	(4,213		)	(4,933		)	(12,638		)	(14,799		)	(699		)	(986		)	(2,098		)	(2,958		)
State administrative fees and insurance bond premiums	—			—			—			—			1,345			1,635			3,004			3,545			—			—			—			—			1,496			1,795			4,500			5,340
Legal and administrative costs	—			—			—			—			591			648			1,182			1,296			—			—			—			—			591			648			1,773			1,943
Net periodic (benefit) cost	$	(269	)	$	(1,014	)	$	(539	)	$	(2,029	)	$	6,425		$	6,709		$	13,164		$	13,693		$	(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 ~~six~~nine months ended ~~June~~September 30, 2013, $~~5,372~~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 ~~six~~nine months ended ~~June~~September 30, 2013, $~~14,946~~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 ~~six-month periods~~ was ~~2,969.4%~~809.9% and ~~24.3%~~20.2%, respectively.

The rate for the ~~six~~nine months ended ~~June~~September 30, 2013 differs from the U.S. federal statutory rate of 35% primarily due to a $~~25,471~~$111,104 income tax charge for excess depletion, $~~8,269~~$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 ~~six~~nine months ended ~~June~~September 30, 2012 differs from the U.S. federal statutory rate of 35% primarily due to a $~~39,275~~$53,932 benefit recorded for excess ~~depletion.~~depletion, $48,976 discrete income tax charge related to the gain on the sale of non-producing North Powder River Basin assets, $983 discrete 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 $1,786 discrete 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 ~~June~~September 30, 2013 and 2012 were $22,770 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 ~~six~~nine months ended ~~June~~September 30, 2013 and ~~2012~~.2012.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of ~~June~~September 30, 2013 and 2012,, the Company reported an accrued interest liability relating to uncertain tax positions of $~~5,505~~$5,851 and $~~6,429~~$7,095, respectively. The accrued interest liability includes $~~675~~$1,020 and $~~1,055~~$1,722 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012,, respectively.

CONSOL Energy recognizes penalties accrued related to ~~uncertain~~unrecognized tax ~~positions~~benefits in its income tax expense. As of ~~June~~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:


	June 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
Coal	$	52,406	$	78,825	$	58,050	$	78,825
Merchandise for resale	36,476		35,363		37,792		35,363
Supplies	139,112		133,578		142,506		133,578
Total Inventories	$	227,994	$	247,766	$	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 $~~18,734~~18,683 and $19,700 at ~~June~~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 ~~June~~September 30, 2013, there were letters of credit outstanding against the facility of $~~159,281~~155,636. CONSOL Energy management believes that these ~~guarantees~~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 $~~440~~416 and $~~913~~1,328 for three and ~~six~~nine months ended ~~June~~September 30, 2013, respectively. Costs associated with the receivables facility totaled $~~437~~420 and $~~856~~1,276 for three and ~~six~~nine months ended ~~June~~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 ~~June~~September 30, 2013 and December 31, 2012, eligible accounts receivable totaled $~~181,000~~ ~~and~~ $200,000~~, respectively.~~. There was no subordinated retained interest at ~~June~~September 30, 2013 and at December 31, 2012. There were $~~40,719~~44,364 of borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of ~~June~~September 30, 2013 and $37,846 at December 31, ~~2012.~~2012. The accounts receivable securitization program increased $~~2,873~~6,518 in the ~~six~~nine months ended ~~June~~September 30, 2013 and there was no change in the ~~six~~nine months ended ~~June~~September 30, ~~2012.~~2012. The increase is reflected in the Net Cash ~~Provided by (Used in)~~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:


	June 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
Coal and other plant and equipment	$	6,086,734	$	6,030,620	$	6,207,105	$	6,030,620
Intangible drilling cost	1,721,384		1,550,297		1,830,666		1,550,297
Proven gas properties	1,597,626		1,596,838		1,601,106		1,596,838
Coal properties and surface lands	1,455,541		1,346,151		1,449,526		1,346,151
Unproven gas properties	1,371,532		1,266,017		1,383,921		1,266,017
Gas gathering equipment	1,034,927		1,006,882		1,046,495		1,006,882
Airshafts	727,674		706,388		746,134		706,388
Mine development	583,494		537,939		608,630		537,939
Leased coal lands	529,700		529,758		529,409		529,758
Gas wells and related equipment	542,284		492,367		623,176		492,367
Coal advance mining royalties	396,034		391,501		397,015		391,501
Other gas assets	125,194		82,217		125,635		82,217
Gas advance royalties	22,127		8,229		22,286		8,229
Total Property Plant and Equipment	16,194,251		15,545,204		16,571,104		15,545,204
Less: Accumulated DD&A	5,770,506		5,354,237		5,940,247		5,354,237
Total Net PP&E	$	10,423,745	$	10,190,967	$	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, ~~LLC (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 ~~itself~~ 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 weCONSOL 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. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase. Noble EnergyThe Company has ~~submitted a final title defect notice to CONSOL Energy. Based on our~~substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, the Company has ~~asserted title~~addressed defects with respect to approximately ~~75,000~~86.498 gross deal acres, having a carry value of approximately $~~481,000~~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. We are~~addressed to the full satisfaction of both parties. The Company is working closely with Noble to address these remaining and final alleged ~~defects and we believe that we will resolve most of those defects favorably to CONSOL Energy.~~defects. To date, ~~we have~~the Company has conceded defects which have an aggregate value of approximately $~~57,000~~204,000 in excess of the applicable deductibles. The impact of these conceded defects was $~~2,470~~12,983 and $~~8,780~~21,763 of expense for the three and ~~six~~nine months ended ~~June~~September 30, 2013 and iswas 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 ~~June~~September 30, 2013:

Shale Play

Industry Participation Agreement Partner

Industry Participation Agreement Date

Drilling Carries Remaining*

Industry Participation Agreement Partner

Industry Participation Agreement Date

Drilling Carries Remaining*

Marcellus

Noble Energy, Inc.

September 30, 2011

2,034,785

Noble Energy, Inc.

September 30, 2011

1,885,785

Utica

Hess Ohio Developments, LLC

October 21, 2011

279,248

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 Energy.~~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 ~~3.44~~3.96 to 1.00 at ~~June~~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 ~~3.65~~3.21 to 1.00 at ~~June~~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 ~~0.12~~0.11 to 1.00 at ~~June~~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 ~~June~~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 ~~1.20~~0.75 to 1.00 at ~~June~~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 ~~36.85~~28.55 to 1.00 at ~~June~~September 30, 2013. At ~~June~~September 30, 2013, the $1,000,000 facility had $~~173,000~~47,000 borrowings outstanding and $70,051 of letters of credit outstanding, leaving $~~756,949~~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 ~~six~~nine months ended ~~June~~September 30, 2013 was ~~1.69%~~1.80% and 1.76%, respectively. Accrued interest of $625 and $29 iswas included in Other Accrued Liabilities in the Consolidated Balance Sheet at ~~June~~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 ~~June~~September 30, 2013.

NOTE 10—LONG-TERM DEBT:


	June 30, 2013		December 31, 2012		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	$	1,500,000	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000		1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		250,000		250,000		250,000
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865		102,865		102,865
Advance royalty commitments (7.43% weighted average interest rate for June 30, 2013 and December 31, 2012)	20,394		20,394
Other long-term notes maturing at various dates through 2031 (total value of $6,612 and $7,300 less unamortized discount of $1,286 and $1,542 at June 30, 2013 and December 31, 2012, respectively).	5,326		5,758
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
	3,128,585		3,129,017		3,128,361		3,129,017
Less amounts due in one year *	4,585		4,544		4,606		4,544
Long-Term Debt	$	3,124,000	$	3,124,473	$	3,123,755	$	3,124,473

* Excludes current portion of Capital Lease Obligations of $~~8,837~~8,576 and $8,941 at ~~June~~September 30, 2013 and December 31, 2012, respectively.

Accrued interest related to Long-Term Debt of $~~63,269~~113,589 and $63,363 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at ~~June~~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

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 iswas 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 $~~11,000~~12,800. CONSOL Energy recognized no$576 in expense in Cost of Goods Sold and Other charges in the ~~three or six~~nine months ended ~~June~~September 30, 2013 and ~~2012, respectively.~~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 ~~$430~~$2,563 in the ~~six~~nine months ended ~~June~~September 30, ~~2013. No funding was made~~2013 and funded $400 in the ~~six~~nine months ended ~~June~~September 30, 2012. As of ~~June~~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 $~~4,369~~3,805. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at ~~June~~September 30, 2013 is $~~2,762~~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 iswas included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company's underground longwall mining activities at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently breached the dam, thereby eliminating the Ryerson Park Lake. ~~The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resource damages totaling $58,000.~~ In October 2008, the Common Pleas Court ruled that natural resource damages were not recoverable and referred the Commonwealth's claim to the Pennsylvania Department of Environmental Protection (DEP). In February 2010, the DEP issued

~~an interim report, concluding that the alleged damage was subsidence related. The DEP estimated the cost of repair to be approximately~~ ~~$20,000~~. The Company appealed the DEP's findings to the Pennsylvania Environmental Hearing Board (PEHB). In April 2013, this Company and the Commonwealth entered into a Settlement Agreement and Release settling all of the Commonwealth's claims regarding the Dam and the 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 certain coal and mining rights in an area of the Bailey Mine where a mining permit application is currently pending.

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. ~~The~~On August 14, 2013, the Panel, ~~is currently considering SCE&G's attorney fee claim of $1,873, which has been vigorously opposed~~over vigorous objection by CONSOL, ~~Energy.~~awarded SCE&G $1,232 for attorneys’ fees and expenses. We ~~have~~had established an accrual to cover our estimated liability for this ~~case.~~case, and have paid the final award in the nine months ended September 30, 2013. This ~~accrual~~matter is ~~immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.~~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 ~~claimant,~~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, and the~~2013. The District Judge ~~has scheduled~~heard argument on the Objections on September 12, ~~2013.~~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 iswas 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, and the~~2013. The District Judge ~~has scheduled~~heard argument on the Objections on September 12, ~~2013.~~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 iswas 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 $~~20,200~~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 ~~has been scheduled~~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:~~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. ~~Without first seeking the required leave of Court, plaintiffs~~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. ~~The defendants have moved to strike the Sur Reply and have asked~~Based on Plaintiffs’ challenge, the Court on August 1, 2013, entered a Certificate pursuant to ~~deny plaintiffs' after-the-fact Motion~~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 ~~Leave to file~~ the ~~Sur Reply brief.~~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 ~~now scheduled~~anticipated for ~~October 21, 2013.~~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 ~~amended~~recently been permitted to file its ~~complaint twice~~Third Amended Complaint to include additional allegations that CONSOL Energy ~~and Dominion Resources are liable for their subsidiaries' actions and that~~has slandered Rowland's ~~title has been slandered. Motions~~title. A motion to dismiss ~~have been denied, discovery is proceeding but stayed pending mediation.~~will be filed. Initial mediation efforts have been ~~unsuccessful but settlement discussions are continuing.~~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. ~~If they wish to do so, plaintiffs have until~~ 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 ~~June~~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										Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years		Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	190,157	$	95,847	$	94,310	$	—	$	—	$	190,358	$	71,624	$	118,734	$	—	$	—
Environmental	56,294		54,566		1,728		—		—		56,294		54,566		1,728		—		—
Other	83,246		31,015		52,231		—		—		83,246		34,488		48,758		—		—
Total Letters of Credit	329,697		181,428		148,269		—		—		329,898		160,678		169,220		—		—
Surety Bonds:
Employee-Related	204,884		194,884		10,000		—		—		204,884		204,884		—		—		—
Environmental	533,725		527,938		5,787		—		—		537,167		495,017		42,150		—		—
Other	30,946		30,935		10		—		1		31,955		31,719		235		—		1
Total Surety Bonds	769,555		753,757		15,797		—		1		774,006		731,620		42,385		—		1
Total Commitments	$	1,099,252	$	935,185	$	164,066	$	—	$	1	$	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 ~~June~~September 30, 2013, the purchase obligations for each of the next five years and beyond were as follows:


Obligations Due	Amount		Amount
Less than 1 year	$	258,380	$	393,709
1 - 3 years	164,240		253,025
3 - 5 years	131,751		189,138
More than 5 years	405,934		419,240
Total Purchase Obligations	$	960,305	$	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

Three Months Ended Six Months Ended
June 30, June 30,
2013 2012 2013 2012
Major equipment purchases $ 15,116
$ 31,989
$ 48,542
$ 45,175
Firm transportation expense 31,017
15,822
59,542
30,867
Gas drilling obligations 25,904
28,517
54,768
58,093
Other —
129
—
427
Total costs related to purchase obligations $ 72,037
$ 76,457
$ 162,852
$ 134,562

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 ~~requires~~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 ~~revenues.~~sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted ~~revenues~~sales from the underlying commodity. As of ~~June~~September 30, 2013, the total notional amount of the Company’s outstanding natural gas swap contracts was ~~197.7~~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. ~~During~~Assuming no changes in price during the next twelve months, $~~49,614~~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 ~~June~~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 $~~120,973~~107,366 and a liability of $~~4,854~~5,252. The total asset is comprised of $~~82,061~~75,735 and $~~38,912~~31,631 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $~~860~~746 and $~~3,994~~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 June 30,						For the Three Months Ended September 30,
		2013			2012			2013		2012
Natural Gas Price Swaps	Natural Gas Price Swaps						Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	Beginning Balance – Accumulated OCI	$	35,453		$	179,915	Beginning Balance – Accumulated OCI	$	71,674	$	132,731
Gain/(Loss) recognized in Accumulated OCI	Gain/(Loss) recognized in Accumulated OCI	$	45,749		$	10,663	Gain/(Loss) recognized in Accumulated OCI	$	13,246	$	(6,459	)
Less: Gain reclassified from Accumulated OCI into Outside Sales	Less: Gain reclassified from Accumulated OCI into Outside Sales	$	9,528		$	57,847	Less: Gain reclassified from Accumulated OCI into Outside Sales	$	24,354	$	47,809
Ending Balance – Accumulated OCI	Ending Balance – Accumulated OCI	$	71,674		$	132,731	Ending Balance – Accumulated OCI	$	60,566	$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(3,753	)	$	882	Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	2,592	$	1,732


		For the Six Months Ended June 30,						For the Nine Months Ended September 30,
		2013			2012			2013			2012
Natural Gas Price Swaps	Natural Gas Price Swaps						Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	Beginning Balance – Accumulated OCI	$	76,761		$	151,780	Beginning Balance – Accumulated OCI	$	76,761		$	151,780
Gain/(Loss) recognized in Accumulated OCI	Gain/(Loss) recognized in Accumulated OCI	$	27,154		$	86,739	Gain/(Loss) recognized in Accumulated OCI	$	40,400		$	80,280
Less: Gain reclassified from Accumulated OCI into Outside Sales	Less: Gain reclassified from Accumulated OCI into Outside Sales	$	32,241		$	105,788	Less: Gain reclassified from Accumulated OCI into Outside Sales	$	56,595		$	153,597
Ending Balance – Accumulated OCI	Ending Balance – Accumulated OCI	$	71,674		$	132,731	Ending Balance – Accumulated OCI	$	60,566		$	78,463
Gain/(Loss) recognized in Outside Sales for ineffectiveness	Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(2,712	)	$	47	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 June 30, 2013						Fair Value Measurements at December 31, 2012						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)		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	$	—	$	116,119	$	—	$	—	$	128,945	$	—	$	—	$	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:


	June 30, 2013						December 31, 2012						September 30, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	71,938		$	71,938		$	21,878		$	21,878		$	21,086		$	21,086		$	21,878		$	21,878
Restricted Cash (a)	$	—		$	—		$	68,673		$	68,673		$	12,263		$	12,263		$	68,673		$	68,673
Short-Term Notes Payable	$	(173,000	)	$	(173,000	)	$	(25,073	)	$	(25,073	)	$	(47,000	)	$	(47,000	)	$	(25,073	)	$	(25,073	)
Borrowings Under Securitization Facility	$	(40,719	)	$	(40,719	)	$	(37,846	)	$	(37,846	)	$	(44,364	)	$	(44,364	)	$	(37,846	)	$	(37,846	)
Long-Term Debt	$	(3,128,585	)	$	(3,270,812	)	$	(3,129,017	)	$	(3,378,058	)	$	(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 ~~located~~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 ~~six~~nine months ended ~~June~~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 ~~six~~nine months ended ~~June~~September 30, 2013, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the ~~six~~nine months ended ~~June~~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.

Industry segment results for the three months ended ~~June~~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			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	$	697,945	$	111,006	$	57,115	$	5,005		$	871,071	$	87,799	$	46,577	$	33,745		$	3,115		$	171,236		$	83,469		$	—		$	1,125,776	(A)	$	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	—		—		—		—			—		—		—		—			1,406			1,406			—			—			1,406			—		—		—		—			—		—		—		—			1,608			1,608			—			—			1,608
Sales—gas royalty interests	—		—		—		—			—		—		—		—			17,028			17,028			—			—			17,028			—		—		—		—			—		—		—		—			15,506			15,506			—			—			15,506
Freight—outside	—		—		—		10,125			10,125		—		—		—			—			—			—			—			10,125			—		—		—		11,563			11,563		—		—		—			—			—			—			—			11,563
Intersegment transfers	—		—		—		—			—		—		—		—			926			926			32,428			(33,354		)	—			—		—		—		—			—		—		—		—			601			601			32,213			(32,814		)	—
Total Sales and Freight	$	697,945	$	111,006	$	57,115	$	15,130		$	881,196	$	87,799	$	46,577	$	33,745		$	22,475		$	190,596		$	115,897		$	(33,354	)	$	1,154,335		$	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	$	103,768	$	30,819	$	17,245	$	(86,354	)	$	65,478	$	22,124	$	11,680	$	(5,576	)	$	(32,838	)	$	(4,610	)	$	(883	)	$	(58,176	)	$	1,809	(B)	$	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										$	5,600,934											$	6,170,531		$	363,819		$	617,644		$	12,752,928	(C)										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(C)
Depreciation, depletion and amortization										$	100,751											$	52,236		$	6,320		$	—		$	159,307											$	104,530											$	58,444		$	6,178		$	—		$	169,152
Capital expenditures										$	157,558											$	188,463		$	6,007		$	—		$	352,028											$	156,730											$	273,474		$	7,705		$	—		$	437,909

(A) Included in the Coal segment are sales of $~~157,318~~164,572 to First Energy and $~~138,700~~119,707 to Xcoal Energy & Resources each comprising over 10% of sales.

(B) Includes equity in earnings of unconsolidated affiliates of $~~11,526~~(1,682), $~~1,030~~5,307 and $~~(686)~~(16) for Coal, Gas and All Other, respectively.

(C) Includes investments in unconsolidated equity affiliates of $~~22,119~~20,131, $~~170,589~~183,895 and $~~63,389~~57,192 for Coal, Gas and All Other, respectively.

Industry segment results for the three months ended ~~June~~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			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	$	748,303	$	120,481	$	71,250	$	4,736	$	944,770	$	88,080	$	23,730	$	34,207		$	2,082		$	148,099	$	96,424		$	—		$	1,189,293	(D)	$	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	—		—		—		—		—		—		—		—			651			651		—			—			651			—		—		—		—			—		—		—		—			953			953		—		—			953
Sales—gas royalty interests	—		—		—		—		—		—		—		—			9,533			9,533		—			—			9,533			—		—		—		—			—		—		—		—			12,968			12,968		—		—			12,968
Freight—outside	—		—		—		49,472		49,472		—		—		—			—			—		—			—			49,472			—		—		—		27,430			27,430		—		—		—			—			—		—		—			27,430
Intersegment transfers	—		—		—		—		—		—		—		—			360			360		36,136			(36,496		)	—			—		—		—		—			—		—		—		—			345			345		37,987		(38,332		)	—
Total Sales and Freight	$	748,303	$	120,481	$	71,250	$	54,208	$	994,242	$	88,080	$	23,730	$	34,207		$	12,626		$	158,643	$	132,560		$	(36,496	)	$	1,248,949		$	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	$	133,697	$	42,780	$	19,418	$	61,286	$	257,181	$	24,344	$	4,835	$	(2,410	)	$	(25,625	)	$	1,144	$	14,962		$	(61,632	)	$	211,655	(E)	$	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									$	5,445,502											$	5,970,939	$	360,673		$	820,782		$	12,597,896	(F)										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594		(F)
Depreciation, depletion and amortization									$	100,684											$	47,326	$	(5,782	)	$	11,596		$	153,824											$	95,702											$	52,215	$	—	$	5,960		$	153,877
Capital expenditures									$	253,587											$	143,206	$	11,160		$	—		$	407,953											$	254,864											$	166,617	$	16,141	$	—		$	437,622


(D)	Included in the Coal segment are sales of $~~136,576~~129,014 to First Energy ~~and~~ ~~$181,566~~ ~~to Xcoal Energy & Resources each comprising~~which comprises over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $~~1,483~~(3,504), $~~2,037~~2,503 and $~~3,648~~8,574 for Coal, Gas and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $~~21,090~~19,750, $~~132,545~~135,048 and $~~55,638~~58,910 for Coal, Gas and All Other, respectively.

Industry segment results for the ~~six~~nine months ended ~~June~~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			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	$	1,459,217	$	257,834	$	115,737	$	10,668		$	1,843,456	$	171,439	$	94,988	$	66,181		$	6,470		$	339,078		$	169,407		$	—		$	2,351,941	(G)	$	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	—		—		—		—			—		—		—		—			2,764			2,764			—			—			2,764			—		—		—		—			—		—		—		—			4,372			4,372			—			—			4,372
Sales—gas royalty interests	—		—		—		—			—		—		—		—			31,232			31,232			—			—			31,232			—		—		—		—			—		—		—		—			46,738			46,738			—			—			46,738
Freight—outside	—		—		—		24,186			24,186		—		—		—			—			—			—			—			24,186			—		—		—		35,749			35,749		—		—		—			—			—			—			—			35,749
Intersegment transfers	—		—		—		—			—		—		—		—			1,762			1,762			67,905			(69,667		)	—			—		—		—		—			—		—		—		—			2,363			2,363			100,118			(102,481		)	—
Total Sales and Freight	$	1,459,217	$	257,834	$	115,737	$	34,854		$	1,867,642	$	171,439	$	94,988	$	66,181		$	42,228		$	374,836		$	237,312		$	(69,667	)	$	2,410,123		$	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	$	232,200	$	85,536	$	30,597	$	(189,353	)	$	158,980	$	43,436	$	25,448	$	(9,737	)	$	(64,397	)	$	(5,250	)	$	(41,435	)	$	(111,785	)	$	510	(H)	$	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										$	5,600,934											$	6,170,531		$	363,819		$	617,644		$	12,752,928	(I)										$	5,792,969											$	5,994,072		$	356,848		$	593,183		$	12,737,072	(I)
Depreciation, depletion and amortization										$	203,462											$	104,635		$	12,525		$	—		$	320,622											$	307,992											$	163,079		$	18,703		$	—		$	489,774
Capital expenditures										$	354,896											$	395,593		$	7,511		$	—		$	758,000											$	511,626											$	669,067		$	15,216		$	—		$	1,195,909

(G) Included in the Coal segment are sales of $~~328,300~~492,872 to First Energy and $~~321,821~~441,528 to Xcoal Energy & Resources each comprising over 10% of sales.

(H) Includes equity in earnings of unconsolidated affiliates of $~~12,343~~10,661, $~~4,212~~9,519 and $~~112~~96 for Coal, Gas and All Other, respectively.

(I) Includes investments in unconsolidated equity affiliates of $~~22,119~~20,131, $~~170,589~~183,895 and $~~63,389~~57,192 for Coal, Gas and All Other, respectively.

Industry segment results for the ~~six~~nine months ended ~~June~~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			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	$	1,560,356	$	293,221	$	131,818	$	13,691	$	1,999,086	$	187,615	$	47,521	$	68,580		$	4,586		$	308,302	$	193,376	$	—		$	2,500,764	(J)	$	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	—		—		—		—		—		—		—		—			1,490			1,490		—		—			1,490			—		—		—		—			—		—		—		—			2,443			2,443		—		—			2,443
Sales—gas royalty interests	—		—		—		—		—		—		—		—			21,739			21,739		—		—			21,739			—		—		—		—			—		—		—		—			34,707			34,707		—		—			34,707
Freight—outside	—		—		—		98,765		98,765		—		—		—			—			—		—		—			98,765			—		—		—		126,195			126,195		—		—		—			—			—		—		—			126,195
Intersegment transfers	—		—		—		—		—		—		—		—			826			826		73,345		(74,171		)	—			—		—		—		—			—		—		—		—			1,171			1,171		111,332		(112,503		)	—
Total Sales and Freight	$	1,560,356	$	293,221	$	131,818	$	112,456	$	2,097,851	$	187,615	$	47,521	$	68,580		$	28,641		$	332,357	$	266,721	$	(74,171	)	$	2,622,758		$	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	$	262,146	$	122,121	$	35,354	$	30	$	419,651	$	60,734	$	8,086	$	(6,132	)	$	(49,044	)	$	13,644	$	19,045	$	(122,108	)	$	330,232	(K)	$	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									$	5,445,502											$	5,970,939	$	360,673	$	820,782		$	12,597,896	(L)										$	5,594,926											$	5,870,451	$	376,400	$	714,817		$	12,556,594	(L)
Depreciation, depletion and amortization									$	201,446											$	96,129	$	—	$	11,596		$	309,171											$	297,148											$	148,344	$	—	$	17,556		$	463,048
Capital expenditures									$	448,016											$	241,661	$	24,722	$	—		$	714,399											$	702,880											$	408,278	$	40,863	$	—		$	1,152,021


(J)	Included in the Coal segment are sales of $~~280,731~~409,745 to First Energy and $~~319,907~~382,950 to Xcoal Energy & Resources each comprising over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $~~6,290~~7,588, $~~3,981~~6,484 and $~~4,832~~8,604 for Coal, Gas and All Other, respectively.

(L) Includes investments in unconsolidated equity affiliates of $~~21,090~~19,750, $~~132,545~~135,048 and $~~55,638~~58,910 for Coal, Gas and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:


	For the Three Months Ended June 30,						For the Six Months Ended June 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Segment Earnings Before Income Taxes for total reportable business segments	$	60,868		$	258,325		$	153,730		$	433,295		$	83,938		$	19,468		$	237,668		$	452,763
Segment (Loss) Earnings Before Income Taxes for all other businesses	(883		)	14,962			(41,435		)	19,045			(6,991		)	8,494			(48,426		)	27,539
Interest expense, net and other non-operating activity (M)	(56,406		)	(58,943		)	(109,066		)	(118,985		)	(57,482		)	(56,338		)	(166,548		)	(175,323		)
Other Corporate Items (M)	(1,770		)	(2,689		)	(2,719		)	(3,123		)	(8,891		)	(2,995		)	(11,610		)	(6,118		)
Earnings Before Income Taxes	$	1,809		$	211,655		$	510		$	330,232		$	10,574		$	(31,371	)	$	11,084		$	298,861


Total Assets:	June 30,				September 30,
	2013		2012		2013		2012
Segment assets for total reportable business segments	$	11,771,465	$	11,416,441	$	11,787,041	$	11,465,377
Segment assets for all other businesses	363,819		360,673		356,848		376,400
Items excluded from segment assets:
Cash and other investments (M)	45,905		186,611		17,988		40,331
Recoverable income taxes	1,930		—		—		12,132
Deferred tax assets	531,707		588,722		538,930		618,742
Bond issuance costs	38,102		45,449		36,265		43,612
Total Consolidated Assets	$	12,752,928	$	12,597,896	$	12,737,072	$	12,556,594

_________________________

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

NOTE 15—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000, 8.000% per annum 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 ~~June~~September 30, 2013 (unaudited):


	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated			Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	172,161		$	897,541		$	53,610		$	2,464		$	1,125,776		$	—		$	193,381		$	911,732		$	54,174		$	827		$	1,160,114
Sales—Gas Royalty Interests	—			17,028			—			—			—			17,028			—			15,506			—			—			—			15,506
Sales—Purchased Gas	—			1,406			—			—			—			1,406			—			1,608			—			—			—			1,608
Freight—Outside	—			—			10,125			—			—			10,125			—			—			11,563			—			—			11,563
Other Income	198,207			11,235			45,706			5,404			(198,207		)	62,345			78,203			12,596			25,103			4,928			(78,203		)	42,627
Total Revenue and Other Income	198,207			201,830			953,372			59,014			(195,743		)	1,216,680			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)	4,249			125,632			660,137			53,467			12,393			855,878			37,591			128,402			620,652			54,857			9,586			851,088
Gas Royalty Interests Costs	—			13,544			—			—			(10		)	13,534			—			12,874			—			—			(10		)	12,864
Purchased Gas Costs	—			1,061			—			—			—			1,061			—			941			—			—			—			941
Related Party Activity	35,231			—			(50,571		)	436			14,904			—			9,710			—			(29,271		)	458			19,103			—
Freight Expense	—			—			10,125			—			—			10,125			—			—			11,563			—			—			11,563
Selling, General and Administrative Expenses	—			11,717			25,058			348			—			37,123			—			11,600			21,582			290			—			33,472
Depreciation, Depletion and Amortization	3,252			52,236			103,321			498			—			159,307			3,288			58,444			106,910			510			—			169,152
Interest Expense	50,807			2,136			1,679			10			(114		)	54,518			52,165			2,578			1,548			13			(3		)	56,301
Taxes Other Than Income	88			—			82,507			730			—			83,325			165			9,847			74,730			721			—			85,463
Total Costs	93,627			206,326			832,256			55,489			27,173			1,214,871			102,919			224,686			807,714			56,849			28,676			1,220,844
Earnings (Loss) Before Income Taxes	104,580			(4,496		)	121,116			3,525			(222,916		)	1,809			(24,716		)	(1,595		)	140,684			2,253			(106,052		)	10,574
Income Tax Expense (Benefit)	117,106			(1,747		)	(96,692		)	(4,045		)	—			14,622			38,935			(602		)	37,143			(853		)	—			74,623
Net (Loss) Income	(12,526		)	(2,749		)	217,808			7,570			(222,916		)	(12,813		)	(63,651		)	(993		)	103,541			3,106			(106,052		)	(64,049		)
Add: Net Loss Attributable to Noncontrolling Interest	—			287			—			—			—			287			—			398			—			—			—			398
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	(2,462	)	$	217,808		$	7,570		$	(222,916	)	$	(12,526	)	$	(63,651	)	$	(595	)	$	103,541		$	3,106		$	(106,052	)	$	(63,651	)

Balance Sheet at ~~June~~September 30, 2013 (unaudited):


	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated			Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	45,267	$	26,851		$	122		$	(302	)	$	—		$	71,938		$	16,187	$	3,847		$	—		$	1,052	$	—		$	21,086
Accounts and Notes Receivable:
Trade	—		62,013			—			285,354			—			347,367			—		60,255			—			376,133		—			436,388
Notes Receivable	234		323,835			26,908			—			—			350,977			1,193		—			24,620			—		—			25,813
Other Receivables	4,449		133,895			8,436			4,489			—			151,269			3,866		144,253			7,780			5,032		—			160,931
Accounts Receivable—Securitized	—		—			—			40,719			—			40,719			—		—			—			44,364		—			44,364
Inventories	—		14,619			176,899			36,476			—			227,994			—		15,679			184,877			37,792		—			238,348
Deferred Income Taxes	169,905		(26,901		)	—			—			—			143,004			106,291		(24,466		)	—			—		—			81,825
Recoverable Income Taxes	16,038		(14,108		)	—			—			—			1,930
Restricted Cash																		—		—			12,263			—		—			12,263
Prepaid Expenses	12,795		86,893			36,494			1,461			—			137,643			37,054		81,970			41,981			1,413		—			162,418
Total Current Assets	248,688		607,097			248,859			368,197			—			1,472,841			164,591		281,538			271,521			465,786		—			1,183,436
Property, Plant and Equipment:
Property, Plant and Equipment	221,174		6,368,437			9,578,914			25,726			—			16,194,251			218,303		6,586,647			9,740,510			25,644		—			16,571,104
Less-Accumulated Depreciation, Depletion and Amortization	134,785		1,064,498			4,552,589			18,634			—			5,770,506			139,157		1,122,401			4,659,763			18,926		—			5,940,247
Total Property, Plant and Equipment-Net	86,389		5,303,939			5,026,325			7,092			—			10,423,745			79,146		5,464,246			5,080,747			6,718		—			10,630,857
Other Assets:
Deferred Income Taxes	820,406		(431,703		)	—			—			—			388,703			875,354		(418,249		)	—			—		—			457,105
Investment in Affiliates	10,128,714		170,589			764,618			—			(10,807,824		)	256,097			10,234,178		183,895			750,771			—		(10,907,626		)	261,218
Notes Receivable	184		—			1,328			—			—			1,512			155		—			—			—		—			155
Other	112,660		47,888			39,568			9,914			—			210,030			109,998		39,916			44,822			9,565		—			204,301
Total Other Assets	11,061,964		(213,226		)	805,514			9,914			(10,807,824		)	856,342			11,219,685		(194,438		)	795,593			9,565		(10,907,626		)	922,779
Total Assets	$	11,397,041	$	5,697,810		$	6,080,698		$	385,203		$	(10,807,824	)	$	12,752,928		$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	193,082	$	208,852		$	48,729		$	10,752		$	—		$	461,415		$	193,491	$	257,487		$	48,128		$	13,076	$	—		$	512,182
Accounts Payable (Recoverable)—Related Parties	3,847,815		65,771			(4,118,674		)	153,288			51,800			—			3,882,644		39,594			(4,202,168		)	241,430		38,500			—
Current Portion Long-Term Debt	1,562		5,972			5,081			807			—			13,422			1,454		6,036			4,914			778		—			13,182
Short-Term Notes Payable	—		224,800			—			—			(51,800		)	173,000			—		85,500			—			—		(38,500		)	47,000
Accrued Income Taxes																		64,059		23,906			—			—		—			87,965
Borrowings Under Securitization Facility	—		—			—			40,719			—			40,719			—		—			—			44,364		—			44,364
Other Accrued Liabilities	140,353		64,908			582,911			10,473			—			798,645			209,321		70,835			578,019			10,729		—			868,904
Total Current Liabilities	4,182,812		570,303			(3,481,953		)	216,039			—			1,487,201			4,350,969		483,358			(3,571,107		)	310,377		—			1,573,597
Long-Term Debt:	3,005,012		43,897			121,252			1,589			—			3,171,750			3,004,976		43,682			121,864			1,409		—			3,171,931
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			2,820,186			—			—			2,820,186			—		—			2,814,234			—		—			2,814,234
Pneumoconiosis Benefits	—		—			177,146			—			—			177,146			—		—			178,508			—		—			178,508
Mine Closing	—		—			459,392			—			—			459,392			—		—			460,515			—		—			460,515
Gas Well Closing	—		115,802			78,144			—			—			193,946			—		118,075			79,018			—		—			197,093
Workers’ Compensation	—		—			155,199			319			—			155,518			—		—			156,242			326		—			156,568
Salary Retirement	109,691		—			—			—			—			109,691			74,108		—			—			—		—			74,108
Reclamation	—		—			50,051			—			—			50,051			—		—			49,487			—		—			49,487
Other	73,875		11,703			17,409			—			—			102,987			75,204		12,227			16,424			—		—			103,855
Total Deferred Credits and Other Liabilities	183,566		127,505			3,757,527			319			—			4,068,917			149,312		130,302			3,754,428			326		—			4,034,368
Total CONSOL Energy Inc. Stockholders’ Equity	4,025,651		4,956,696			5,683,872			167,256			(10,807,824		)	4,025,651			3,958,165		4,894,993			5,842,676			169,957		(10,907,626		)	3,958,165
Noncontrolling Interest	—		(591		)	—			—			—			(591		)	—		(989		)	—			—		—			(989		)
Total Liabilities and Equity	$	11,397,041	$	5,697,810		$	6,080,698		$	385,203		$	(10,807,824	)	$	12,752,928		$	11,463,422	$	5,551,346		$	6,147,861		$	482,069	$	(10,907,626	)	$	12,737,072

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


	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated		Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	148,459	$	976,515	$	64,785	$	(466	)	$	1,189,293	$	—		$	165,448	$	861,009		$	58,405	$	(821	)	$	1,084,041
Sales—Gas Royalty Interests	—			9,533		—		—		—			9,533		—			12,968		—			—		—			12,968
Sales—Purchased Gas	—			651		—		—		—			651		—			953		—			—		—			953
Freight—Outside	—			—		49,472		—		—			49,472		—			—		27,430			—		—			27,430
Other Income	249,780			18,098		30,352		5,215		(97,907		)	205,538		(17,948		)	11,772		170,877			4,917		(134,921		)	34,697
Total Revenue and Other Income	249,780			176,741		1,056,339		70,000		(98,373		)	1,454,487		(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)	22,351			101,695		662,457		62,811		7,575			856,889		18,699			96,619		647,158			57,408		7,646			827,530
Gas Royalty Interests Costs	—			7,131		—		—		(7		)	7,124		—			10,565		—			—		(22		)	10,543
Purchased Gas Costs	—			869		—		—		—			869		—			737		—			—		—			737
Related Party Activity	(14,013		)	—		22,782		447		(9,216		)	—		8,575			—		(18,962		)	427		9,960			—
Freight Expense	—			—		49,472		—		—			49,472		—			—		27,430			—		—			27,430
Selling, General and Administrative Expenses	—			9,313		24,185		234		—			33,732		—			9,906		26,412			363		—			36,681
Depreciation, Depletion and Amortization	2,895			47,326		103,085		518		—			153,824		3,085			52,214		98,060			518		—			153,877
Interest Expense	52,932			1,191		2,560		11		(101		)	56,593		50,811			1,145		2,267			11		(159		)	54,075
Taxes Other Than Income	27			8,164		75,425		713		—			84,329		(504		)	8,426		71,985			680		—			80,587
Total Costs	64,192			175,689		939,966		64,734		(1,749		)	1,242,832		80,666			179,612		854,350			59,407		17,425			1,191,460
Earnings (Loss) Before Income Taxes	185,588			1,052		116,373		5,266		(96,624		)	211,655
Income Tax Expense (Benefit)	32,849			326		23,788		1,982		—			58,945
(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	152,739			726		92,585		3,284		(96,624		)	152,710		(11,368		)	7,096		143,542			2,424		(153,167		)	(11,473		)
Add: Net Loss Attributable to Noncontrolling Interest	—			29		—		—		—			29		—			105		—			—		—			105
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	152,739		$	755	$	92,585	$	3,284	$	(96,624	)	$	152,739
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders															$	(11,368	)	$	7,201	$	143,542		$	2,424	$	(153,167	)	$	(11,368	)

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

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


	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated			Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	340,840		$	1,901,698		$	107,663		$	1,740		$	2,351,941		$	—		$	534,221		$	2,813,430		$	161,837		$	2,567		$	3,512,055
Sales—Gas Royalty Interests	—			31,232			—			—			—			31,232			—			46,738			—			—			—			46,738
Sales—Purchased Gas	—			2,764			—			—			—			2,764			—			4,372			—			—			—			4,372
Freight—Outside	—			—			24,186			—			—			24,186			—			—			35,749			—			—			35,749
Other Income	276,183			24,459			60,961			10,777			(276,183		)	96,197			354,386			37,055			86,064			15,705			(354,386		)	138,824
Total Revenue and Other Income	276,183			399,295			1,986,845			118,440			(274,443		)	2,506,320			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)	80,239			239,984			1,341,842			107,193			19,583			1,788,841			117,830			359,397			1,971,483			162,050			29,169			2,639,929
Gas Royalty Interests Costs	—			25,361			—			—			(21		)	25,340			—			38,235			—			—			(31		)	38,204
Purchased Gas Costs	—			2,020			—			—			—			2,020			—			2,961			—			—			—			2,961
Related Party Activity	22,675			—			(58,349		)	840			34,834			—			32,385			—			(87,620		)	1,298			53,937			—
Freight Expense	—			—			24,186			—			—			24,186			—			—			35,749			—			—			35,749
Selling, General and Administrative Expenses	—			21,829			48,305			659			—			70,793			—			33,429			69,887			949			—			104,265
Depreciation, Depletion and Amortization	6,447			104,635			208,558			982			—			320,622			9,735			163,079			315,468			1,492			—			489,774
Interest Expense	100,976			3,797			3,323			21			(221		)	107,896			153,141			6,375			4,871			34			(224		)	164,197
Taxes Other Than Income	265			6,698			157,513			1,636			—			166,112			430			25,534			223,254			2,357			—			251,575
Total Costs	210,602			404,324			1,725,378			111,331			54,175			2,505,810			313,521			629,010			2,533,092			168,180			82,851			3,726,654
Earnings (Loss) Before Income Taxes	65,581			(5,029		)	261,467			7,109			(328,618		)	510			40,865			(6,624		)	402,151			9,362			(434,670		)	11,084
Income Tax Expense (Benefit)	79,671			(1,955		)	(59,883		)	(2,689		)	—			15,144			118,606			(2,557		)	(22,740		)	(3,542		)	—			89,767
Net (Loss) Income	(14,090		)	(3,074		)	321,350			9,798			(328,618		)	(14,634		)	(77,741		)	(4,067		)	424,891			12,904			(434,670		)	(78,683		)
Add: Net Loss Attributable to Noncontrolling Interest	—			544			—			—			—			544			—			942			—			—			—			942
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(14,090	)	$	(2,530	)	$	321,350		$	9,798		$	(328,618	)	$	(14,090	)	$	(77,741	)	$	(3,125	)	$	424,891		$	12,904		$	(434,670	)	$	(77,741	)

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


	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated		Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	309,128	$	2,058,803	$	133,807	$	(974	)	$	2,500,764	$	—		$	474,574	$	2,919,814	$	192,212	$	(1,795	)	$	3,584,805
Sales—Gas Royalty Interests	—			21,739		—		—		—			21,739		—			34,707		—		—		—			34,707
Sales—Purchased Gas	—			1,490		—		—		—			1,490		—			2,443		—		—		—			2,443
Freight—Outside	—			—		98,765		—		—			98,765		—			—		126,195		—		—			126,195
Other Income	417,765			34,403		60,055		11,172		(264,896		)	258,499		399,817			46,177		230,930		16,089		(399,817		)	293,196
Total Revenue and Other Income	417,765			366,760		2,217,623		144,979		(265,870		)	2,881,257		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)	71,531			200,340		1,345,213		129,227		14,619			1,760,930		90,230			296,959		1,992,371		186,635		22,265			2,588,460
Gas Royalty Interests Costs	—			17,386		—		—		(13		)	17,373		—			27,951		—		—		(35		)	27,916
Purchased Gas Costs	—			1,386		—		—		—			1,386		—			2,123		—		—		—			2,123
Related Party Activity	(7,000		)	—		24,040		949		(17,989		)	—		1,575			—		5,078		1,376		(8,029		)	—
Freight Expense	—			—		98,765		—		—			98,765		—			—		126,195		—		—			126,195
Selling, General and Administrative Expenses	—			19,293		52,757		681		—			72,731		—			29,199		79,169		1,044		—			109,412
Depreciation, Depletion and Amortization	5,816			96,129		206,185		1,041		—			309,171		8,901			148,343		304,245		1,559		—			463,048
Interest Expense	107,694			2,409		4,789		22		(201		)	114,713		158,505			3,554		7,056		33		(360		)	168,788
Taxes Other Than Income	663			16,364		157,396		1,533		—			175,956		159			24,790		229,381		2,213		—			256,543
Total Costs	178,704			353,307		1,889,145		133,453		(3,584		)	2,551,025		259,370			532,919		2,743,495		192,860		13,841			3,742,485
Earnings (Loss) Before Income Taxes	239,061			13,453		328,478		11,526		(262,286		)	330,232		140,447			24,982		533,444		15,441		(415,453		)	298,861
Income Tax Expense (Benefit)	(10,874		)	5,273		81,577		4,350		—			80,326
Net (Loss) Income	249,935			8,180		246,901		7,176		(262,286		)	249,906
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	—			29		—		—		—			29		—			134		—		—		—			134
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	249,935		$	8,209	$	246,901	$	7,176	$	(262,286	)	$	249,935
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders															$	238,567		$	15,410	$	390,443	$	9,600	$	(415,453	)	$	238,567

Cash Flow for the ~~Six~~Nine Months Ended ~~June~~September 30, 2013 (unaudited):


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated			Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by Operating Activities	$	35,486		$	263,284		$	46,545		$	(3,721	)	$	51,800		$	393,394
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	$	(7,511	)	$	(395,593	)	$	(354,896	)	$	—		$	—		$	(758,000	)	$	(15,216	)	$	(669,067	)	$	(511,626	)	$	—		$	—		$	(1,195,909	)
Change in Restricted Cash	—			—			68,673			—			—			68,673			—			—			56,410			—			—			56,410
Proceeds from Sales of Assets	—			5,644			235,144			13			—			240,801			—			335,142			263,015			17			—			598,174
Net Investments In Equity Affiliates	—			(22,501		)	5,901			—			—			(16,600		)	—			(30,500		)	12,388			—			—			(18,112		)
Net Cash (Used in) Provided by Investing Activities	$	(7,511	)	$	(412,450	)	$	(45,178	)	$	13		$	—		$	(465,126	)	$	(15,216	)	$	(364,425	)	$	(179,813	)	$	17		$	—		$	(559,437	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	224,800		$	—		$	—		$	(51,800	)	$	173,000		$	—		$	85,500		$	—		$	—		$	(38,500	)	$	47,000
Payments on Miscellaneous Borrowings	(26,280		)	—			(3,555		)	(327		)	—			(30,162		)	(26,591		)	—			(5,122		)	(577		)	—			(32,290		)
Proceeds from Securitization Facility	—			—			—			2,873			—			2,873			—			—			—			6,518			—			6,518
Dividends (Paid) Received	21,399			(50,000		)	—			—			—			(28,601		)
Dividends Received (Paid)																			42,789			(100,000		)	—			—			—			(57,211		)
Proceeds from Issuance of Common Stock	2,497			—			—			—			—			2,497			2,698			—			—			—			—			2,698
Other Financing Activities	2,185			—			—			—			—			2,185			2,925			(4,084		)	4,084			—			—			2,925
Net Cash Provided by (Used in) Financing Activities	$	(199	)	$	174,800		$	(3,555	)	$	2,546		$	(51,800	)	$	121,792		$	21,821		$	(18,584	)	$	(1,038	)	$	5,941		$	(38,500	)	$	(30,360	)

Cash Flow for the ~~Six~~Nine Months Ended ~~June~~September 30, 2012 (unaudited):

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors
Non-
Guarantors
Elimination Consolidated
Net Cash Provided by Operating Activities $ 271,127
$ 124,367
$ (28,281 ) $ 736
$ —
$ 367,949
Cash Flows from Investing Activities:
Capital Expenditures $ (24,722 ) $ (241,661 ) $ (448,016 ) $ —
$ —
$ (714,399 )
Investments in Equity Affiliates —
(35,150 ) (750 ) —
—
(35,900 )
Distributions from Equity Affiliates —
3,500
10,561
—
—
14,061
Proceeds from Sales of Assets 169,500
30,249
52,469
11
—
252,229
Net Cash (Used in) Provided by Investing Activities $ 144,778
$ (243,062 ) $ (385,736 ) $ 11
$ —
$ (484,009 )
Cash Flows from Financing Activities:
Dividends Paid $ 143,167
$ (200,000 ) $ —
$ —
$ —
$ (56,833 )
Other Financing Activities 1,580
(3,751 ) 2
(467 ) —
(2,636 )
Net Cash Provided by (Used in) Financing Activities $ 144,747
$ (203,751 ) $ 2
$ (467 ) $ —
$ (59,469 )



	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	)

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


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated			Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(12,526	)	$	(2,749	)	$	217,808	$	7,570	$	(222,916	)	$	(12,813	)	$	(63,651	)	$	(993	)	$	103,541	$	3,106	$	(106,052	)	$	(64,049	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	42,904			—			42,904		—		(42,904		)	42,904			24,980			—			24,980		—		(24,980		)	24,980
Net (Decrease) Increase in the Value of Cash Flow Hedge	45,749			45,749			—		—		(45,749		)	45,749
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	(9,528		)	(9,528		)	—		—		9,528			(9,528		)	(24,354		)	(24,354		)	—		—		24,354			(24,354		)
Other Comprehensive (Loss) Income:	79,125			36,221			42,904		—		(79,125		)	79,125
Comprehensive Income (Loss)	66,599			33,472			260,712		7,570		(302,041		)	66,312
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	—			287			—		—		—			287			—			398			—		—		—			398
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	66,599		$	33,759		$	260,712	$	7,570	$	(302,041	)	$	66,599
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 ~~June~~September 30, 2012 (Unaudited):

Parent
CNX Gas
Guarantor
Other Subsidiary Guarantors
Non-
Guarantors
Elimination Consolidated
Net Income (Loss) $ 152,739
$ 726
$ 92,585
$ 3,284
$ (96,624 ) $ 152,710
Other Comprehensive Income (Loss):
  Actuarially Determined Long-Term Liability Adjustments 7,586
—
7,586
—
(7,586 ) 7,586
  Net Increase (Decrease) in the Value of Cash Flow Hedge 10,663
10,663
—
—
(10,663 ) 10,663
  Reclassification of Cash Flow Hedge from OCI to Earnings (57,847 ) (57,847 ) —
—
57,847
(57,847 )
Other Comprehensive Income (Loss): (39,598 ) (47,184 ) 7,586
—
39,598
(39,598 )
Comprehensive Income (Loss) 113,141
(46,458 ) 100,171
3,284
(57,026 ) 113,112
  Add: Comprehensive Loss Attributable to Noncontrolling Interest —
29
—
—
—
29
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders $ 113,141
$ (46,429 ) $ 100,171
$ 3,284
$ (57,026 ) $ 113,141



	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	)

Statement of Comprehensive Income for the ~~Six~~Nine Months Ended ~~June~~September 30, 2013 (Unaudited):


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated			Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(14,090	)	$	(3,074	)	$	321,350	$	9,798	$	(328,618	)	$	(14,634	)	$	(77,741	)	$	(4,067	)	$	424,891	$	12,904	$	(434,670	)	$	(78,683	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	88,661			—			88,661		—		(88,661		)	88,661			113,641			—			113,641		—		(113,641		)	113,641
Net (Decrease) Increase in the Value of Cash Flow Hedge	27,154			27,154			—		—		(27,154		)	27,154
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	(32,241		)	(32,241		)	—		—		32,241			(32,241		)	(56,595		)	(56,595		)	—		—		56,595			(56,595		)
Other Comprehensive Income (Loss):	83,574			(5,087		)	88,661		—		(83,574		)	83,574			97,446			(16,195		)	113,641		—		(97,446		)	97,446
Comprehensive Income (Loss)	69,484			(8,161		)	410,011		9,798		(412,192		)	68,940			19,705			(20,262		)	538,532		12,904		(532,116		)	18,763
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			544			—		—		—			544			—			942			—		—		—			942
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	69,484		$	(7,617	)	$	410,011	$	9,798	$	(412,192	)	$	69,484		$	19,705		$	(19,320	)	$	538,532	$	12,904	$	(532,116	)	$	19,705

Statement of Comprehensive Income for the ~~Six~~Nine Months Ended ~~June~~September 30, 2012 (Unaudited):


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated			Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	249,935		$	8,180		$	246,901	$	7,176	$	(262,286	)	$	249,906		$	238,567		$	15,276		$	390,443	$	9,600	$	(415,453	)	$	238,433
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	67,159			—			67,159		—		(67,159		)	67,159			75,080			—			75,080		—		(75,080		)	75,080
Net Increase (Decrease) in the Value of Cash Flow Hedge	86,739			86,739			—		—		(86,739		)	86,739			80,280			80,280			—		—		(80,280		)	80,280
Reclassification of Cash Flow Hedge from OCI to Earnings	(105,788		)	(105,788		)	—		—		105,788			(105,788		)	(153,597		)	(153,597		)	—		—		153,597			(153,597		)
Other Comprehensive Income (Loss):	48,110			(19,049		)	67,159		—		(48,110		)	48,110			1,763			(73,317		)	75,080		—		(1,763		)	1,763
Comprehensive Income (Loss)	298,045			(10,869		)	314,060		7,176		(310,396		)	298,016			240,330			(58,041		)	465,523		9,600		(417,216		)	240,196
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			29			—		—		—			29			—			134			—		—		—			134
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	298,045		$	(10,840	)	$	314,060	$	7,176	$	(310,396	)	$	298,045		$	240,330		$	(57,907	)	$	465,523	$	9,600	$	(417,216	)	$	240,330

NOTE 16—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the the three and ~~six~~nine months ended ~~June~~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 $~~6,129~~9,498 and $~~13,456~~22,954 for the three and ~~six~~nine months ended ~~June~~September 30, 2013, respectively, and were $~~4,262~~5,895 and $~~7,724~~13,619 for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of ~~June~~September 30, 2013 and December 31, 2012, CONSOL Energy and CNX Gas Company had a net payable of $~~1,509~~1,563 and $3,142, respectively, due CONE which was comprised of the following items:


	June 30,			December 31,				September 30,			December 31,
	2013			2012			Location on Balance Sheet	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(733	)	$	(1,336	)	Accounts Receivable–Other	$	(1,380	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(153		)	(341		)	Accounts Receivable–Other	(181		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	2,395			4,837			Accounts Payable	3,124			4,837			Accounts Payable
Net Payable due CONE	$	1,509		$	3,142			$	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.


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

General

~~After a strong market rally early~~Natural gas prices trended downward in the ~~second~~third quarter ~~from extended winter weather, natural gas prices began to decline below~~after rising above $4.00 per MMBtu in ~~June from a~~the first half of the year. When measured by cooling degree days, the summer was both cooler than ~~expected start to summer~~last year and ~~power~~the trailing four year average for the same period, by 9% and 7% respectively. As a result, electric generation ~~switching back to coal from natural gas. Despite~~fell by about 2% compared with the ~~decrease, natural gas prices remained significantly above 2012 levels. During the second~~same quarter ~~cooler than normal temperatures slowly applied~~last year which exerted downward pressure on both thermal coal and natural gas prices as the market cautiously awaited the arrival of summer heat. By the quarter's end, however, the U.S. had experienced 12% fewer cooling degree days than the previous year which negatively impacted thermal coal and natural gas demand.demand for generation fuels. From a fuel-mix perspective, coal-fired electric generation increased by ~~10%~~4% year over year, while higher natural gas prices reduced gas consumption by ~~18%~~10% over the same period. ~~Despite~~Gas production saw a modest growth of around 2% in the ~~cooler weather,~~third quarter. With this decrease in power demand and increase in supply, natural gas underground inventory levels ~~remained below~~increased but were in line with the five year average. Although global economic uncertainties persisted, continued disciplined coal production, slow natural gas production growth and decreasing natural gas net imports helped slow inventory growth and keep prices stable.

~~Second~~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 ~~in April~~ and May. As natural gas prices rose above $4.00 per MMbtu, coal fired electric generation continued to be strong. Early government estimates show that coal-fired generation produced 39% of U.S. power during the second quarter compared with 34% during the same period in 2012, and 40% in the first quarter 2013. Conventional hydropower and nuclear generation gained share during the second quarter, at the expense of coal and natural gas generation. Utility coal stockpiles declined throughout the quarter versus 2012 periods. Increased natural gas prices andreduced domestic coal production ~~cuts~~ contributed to ~~continued~~the stabilization of coal prices.

In the longer term, the outlook for domestic thermal coal continues to face regulatory challenges. In line with ~~President Obama's~~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 ~~coal-fired units and~~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 ~~quarter,~~half, early government data for the second ~~quarter~~half of the year shows a 12% decline in thermal exports, ~~shows a 30% decrease over~~thus causing the full year ~~ago period. For the first half of~~ 2013 ~~thermal coal~~ exports ~~are down 10% over the 2012 first half.~~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.

~~While the~~The U.S. ~~second~~third quarter benchmark price for premium metallurgical coal ~~rose 4% over the prior quarter, spot prices declined to multi-year lows. Price deterioration in the spot market helped push the quarterly benchmark price in the U.S. third quarter 16%~~settled lower than the ~~second~~prior quarter. Toward the end of the quarter, prices began to slightly improve off of three-year lows. The ~~low~~overall current price environment is indicative of ~~the continued~~what has been an oversupplied ~~position of the~~ 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. ~~In response to the weak~~As a result of a challenged seaborne market, annualized U.S. metallurgical coal ~~market,~~ exports in 2013 are down 3% from 2012.

CONSOL Energy has ~~positioned itself by reducing metallurgical~~entered into an agreement to sell Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of its longwall coal ~~production~~mines in ~~2013~~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 ~~increasing~~Blacksville No. 2 Mine. Collectively, these mines produced 28.5 million tons of thermal coal ~~output.~~

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

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:


	Q3 2013		2013		2014		2015		Q4 2013		2013		2014		2015
Estimated Coal Sales (millions of tons)	13.4 - 13.9		55.5 - 57.5		60.4		61.7		13.6 - 14.0		57.0 - 57.4		30.1		33.8
Est. Low-Vol Met Sales	0.7 -0.9		4.0-4.2		4.7		5.2		0.7 - 0.9		4.3 - 4.5		4.2		4.9
Tonnage: Firm	0.2		2.8		—		—		0.7		4.2		0.9		0.8
Avg. Price: Sold (Firm)	$	113.81	$	103.34	$	—	$	—	$	92.27	$	95.34	$	100.62	$	102.50
Est. High-Vol Met Sales	0.6+		2.6+		4.8		6.4		0.5+		2.8+		1.8		1.4
Tonnage: Firm	0.4		2.4		0.2		0.2		0.5		2.8		0.2		0.2
Avg. Price: Sold (Firm)	$	60.55	$	63.67	$	75.53	$	74.74	$	61.31	$	63.27	$	79.80	$	75.33
Est. Thermal Sales	12.3+		49.9+		50.9		50.1		12.4+		49.9+		24.1		27.5
Tonnage: Firm	12.3		49.8		28.1		14.8		12.4		49.9		18.9		10.1
Avg. Price: Sold (Firm)	$	59.02	$	58.93	$	60.45	$	60.99	$	58.19	$	58.94	$	64.05	$	67.00

Note: While ~~most of~~ 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. ~~N/A means not available or not forecast.~~ CONSOL ~~Energy~~ 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 ~~2014~~2015 are ~~7.0~~1.4 million tons, with a ceiling of ~~$55.90~~$72.59 per ton and a floor of ~~$46.32 per ton. Collared tons in 2015 are 8.7 million tons, with a ceiling of $57.43 per ton and a floor of $44.86~~$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 ~~Capital investment costs~~total coal production will be between 56.7 – 57.1 million tons for the ~~BMX Mine to total $710 million. The increase from the prior estimate~~year. Fourth quarter coal production is ~~due, in part, to a lower sales price for development tons, which increases the dollars being capitalized during the development phase.~~

~~CONSOL Energy expects its net gas production~~expected to be between ~~170~~13.6 – ~~175 Bcfe for the year. Third~~14.0 million tons.

Fourth quarter gas production, net to CONSOL, ~~Energy,~~ is expected to be approximately 4346 – 4548 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 ~~six~~nine months ended ~~June~~September 30, 2013. These events include the following:

~~On March 12,~~In August 2013, ~~smoke was detected exiting~~CONSOL Energy completed the ~~Orndoff shaft at~~sale of its 50% interest in the CONSOL ~~Energy's Blacksville No. 2 Mine near Wayne~~Energy/Devon Energy joint venture in ~~Greene County, Pennsylvania. All day shift underground employees~~Alberta, Canada. The properties and coal leases included were ~~safely evacuated~~those related to Grassy Mountain, Bellevue, Adanac, and ~~no one sustained injuries.~~Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24.7 million. 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~~transaction resulted in a ~~pre-tax expense~~$15.3 million gain on the sale of ~~$38.4 million in the six months ended June 30, 2013.~~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 ~~$32.2~~a $38.5 million pre-tax expense adjustment. Many of the lump sum payments in the ~~six~~nine months ended ~~June~~September 30, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive ~~program.~~Plan. Also, pension settlement required the pension plan to be remeasured using updated assumptions at ~~June~~September 30, 2013. The updated assumptions include resetting the discount rate used in the actuarial calculation. See Note 3 - Components of Pension and Other ~~Postretirement~~Post-Employment Benefit (OPEB) Plans Net

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 ~~six~~nine months ended ~~June~~September 30, 2013. As ~~part~~a result of the Company's review of the title defect ~~process the company is~~notice, asserted by Noble, and working ~~through~~in collaboration with ~~its joint venture partner,~~ Noble, ~~Energy,~~ CONSOL Energy ~~conceded title~~has addressed defects ~~on acreage which had a book value to CONSOL Energy~~ of ~~$8.8~~$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 ~~during~~in June 2013.

On March 12, 2013, smoke was detected exiting the ~~three~~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 ~~June~~September 30, 2013.

In the ~~six~~nine months ended ~~June~~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 ~~$20.20~~$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 ~~has been scheduled~~was held by the Court on August 23, ~~2013.~~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~~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

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 will apply to new power plants and to existing plants that make major modifications. If the rules are adopted as proposed, the only new coal fired power plants that will be able to meet the proposed emission limits will be 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. Thus, if finalized the proposed rules could seriously threaten the construction of new coal fired electric generating units. EPA did not meet an April 13, 2013 deadline to publish final rules and, according to the EPA, no specific timetable is set to publish the final rules.

•

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. ~~Although~~ 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 ~~reviewing the notification and any~~evaluating potential modifications that would be required if CONSOL Energy is compelled to modify its application.

Additional pension settlement charges are reasonably possible to occur throughout the remainder of 2013. When lump sum payments from the pension plan exceed the service and interest expense, pension settlement accounting requires unamortized actuarial gains and losses related to the lump sum payouts to be amortized immediately. The threshold for pension settlement was reached as of March 31, 2013 and the corresponding charge has been recognized as discussed above. Additional pension settlement charges throughout the remainder of 2013 could be material to the financial results of CONSOL Energy.

For 2013, CONSOL Energy has stepped up its asset sale process to include coal and gas transportation infrastructure, in order to capitalize on the current market environment and to re-invest proceeds in higher return projects. As previously announced, a process is in place to evaluate and potentially monetize several assets this year as long as fair value is received for those assets.

~~CONSOL Energy is currently evaluating our overall corporate structure to consider different alternatives to unlock additional value for shareholders.~~

Results of Operations

Three Months Ended ~~June~~September 30, 2013 Compared with Three Months Ended ~~June~~September 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $1364 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 ~~June 30, 2013. Net income attributable to CONSOL Energy shareholders was $153~~ ~~million, or~~ ~~$0.67~~ ~~per diluted share, for the three months ended~~ ~~June~~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 $6586 million of earnings before income tax for the three months ended ~~June~~September 30, 2013 compared to $~~257~~8 million for the three months ended ~~June~~September 30, 2012. The total coal division sold ~~13.8~~14.4 million tons of coal produced from CONSOL Energy mines for the three months ended ~~June~~September 30, 2013 compared to ~~14.4~~12.3 million tons for the three months ended ~~June~~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 June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	62.74	$	65.58	$	(2.84	)	(4.3	)%	$	61.26	$	67.31	$	(6.05	)	(9.0	)%
Average Cost of Goods Sold per ton	51.87		52.04		(0.17		)	(0.3	)%	50.46		55.84		(5.38		)	(9.6	)%
Margin per ton sold	$	10.87	$	13.54	$	(2.67	)	(19.7	)%	$	10.80	$	11.47	$	(0.67	)	(5.8	)%

The lower average sales price per ton sold ~~is due to weakened pricing~~reflects a decrease in the global metallurgical and ~~domestic~~ thermal coal ~~markets, along with a reduction in sales tons in the period-to-period comparison.~~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:

~~Direct operating costs improved primarily~~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 ~~decrease~~structural failure occurred at the Bailey Preparation Plant in ~~all~~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 at the Blacksville No. 2 Mine which is the result of the mine being idled until May 20th due to the fire, as previously discussed. Costs were also improved due to the shutdown of the Fola Mining Complex in August 2012.

~~Average direct operating costs were impaired due to CONSOL Energy entering into several new leases for various types of mining equipment at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.~~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.

~~Depreciation, depletion and amortization was improved primarily~~Average direct operating costs were impaired due to ~~lower expense~~CONSOL Energy entering into several new longwall leases in 2013 at ~~the Blacksville No. 2~~our Bailey Mine, ~~related to the mine being shut down due to the fire, the shutdown of operations at the Fola Mining Complex~~Robinson Run Mine, and ~~the timing of assets going into service or being fully depreciated.~~Shoemaker Mine.

The total gas division includes CBM, Shallow Oil and Gas, Marcellus and other gas. The total gas division had a $52 million loss before income tax for the three months ended ~~June~~September 30, 2013 compared to $112 million of income before income tax for the three months ended ~~June~~September 30, 2012. Total gas production was ~~38.6~~46.1 billion cubic feet for the three months ended ~~June~~September 30, 2013 compared to ~~37.3~~39.5 billion cubic feet for the three months ended ~~June~~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 June 30,							For the Three Months Ended September 30,
	2013		2012		Variance		Percent Change	2013		2012		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	4.46	$	3.98	$	0.48	12.1%	$	4.20	$	4.19	$	0.01		0.2%
Average Costs per thousand cubic feet sold	3.77		3.34		0.43		12.9%	3.23		3.38		(0.15		)	(4.4)%
Margin per thousand cubic feet sold	$	0.69	$	0.64	$	0.05	7.8%	$	0.97	$	0.81	$	0.16		19.8%

Total gas division outside sales revenues were $~~173~~193 million for the three months ended ~~June~~September 30, 2013 compared to $~~149~~165 million for the three months ended ~~June~~September 30, 2012. The increase was primarily due to the ~~3.5%~~16.7% increase in volumes sold, along with ~~the~~ a ~~12.1%~~0.2% 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 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 ~~19.7~~24.0 billion cubic feet of our produced gas sales volumes for the three months ended ~~June~~September 30, 2013 at an average price of ~~$4.73~~$4.63 per thousand cubic feet. These financial hedges represented ~~19.1~~19.3 billion cubic feet of our produced gas sales volumes for the three months ended ~~June~~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~~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.

~~Lifting costs increased due to higher accretion expense related to the estimated well plugging liability. Road repair and maintenance costs also increased in the current period.~~

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

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

For the Three Months Ended June 30,
2013 2012 Variance
Percent
Change
Consulting and professional services $ 8
$ 5
$ 3
60.0 %
Contributions 5
3
2
66.7 %
Advertising and promotion 2
2
—
— %
Employee wages and related expenses 13
15
(2 ) (13.3 )%
Miscellaneous 7
7
—
— %
Total Company General and administrative Expenses $ 35
$ 32
$ 3
9.4 %



	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~~Administrative Expenses changed due to the following:

~~Consulting and professional services increased $3 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which are individually significant.~~

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

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

Employee wages and related expenses decreased $2$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.

~~Miscellaneous General~~Advertising and ~~administrative expenses~~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 ~~$65~~$64 million for the three months ended ~~June~~September 30, 2013 ~~compared to $62 million for the three months ended~~and ~~June~~September 30, 2012. ~~The increase of $3 million for total~~Total CONSOL Energy expense ~~was primarily due to required~~remained consistent in the period-to-period comparison even though pension settlement accounting was required resulting in $6 million of ~~$5 million related to~~expense. Pension settlement expenses were required when the lump sum distributions made for the 2013 plan year ~~exceeding~~exceeded the total of the service ~~cost~~ and interest ~~cost~~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 ~~in part,~~ due to a modification to the benefit plan for salaried employees

and aan 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 ~~Postretirement~~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 ~~June~~September 30, 2013 compared to the three months ended ~~June~~September 30, 2012:

The coal segment contributed $6586 million of earnings before income tax in the three months ended ~~June~~September 30, 2013 compared to $~~257~~8 million in the three months ended ~~June~~September 30, 2012. Variances by the individual coal segments are discussed below.


	For the Three Months Ended														Difference to Three Months Ended															For the Three Months Ended														Difference to Three Months Ended
	June 30, 2013														June 30, 2012															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			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	$	698		$	57	$	111		$	—		$	866		$	(50	)	$	(14	)	$	(10	)	$	(2	)	$	(76	)	$	752		$	30	$	98		$	—		$	880		$	85		$	(18	)	$	(12	)	$	—		$	55
Purchased Coal	—			—		—			5			5			—			—			—			2			2			1			—		—			7			8			1			—			—			2			3
Total Outside Sales	698			57		111			5			871			(50		)	(14		)	(10		)	—			(74		)	753			30		98			7			888			86			(18		)	(12		)	2			58
Freight Revenue	—			—		—			10			10			—			—			—			(39		)	(39		)	—			—		—			12			12			—			—			—			(15		)	(15		)
Other Income	1			1		—			46			48			1			—			—			(138		)	(137		)	—			—		—			25			25			(1		)	(1		)	—			7			5
Total Revenue and Other Income	699			58		111			61			929			(49		)	(14		)	(10		)	(177		)	(250		)	753			30		98			44			925			85			(19		)	(12		)	(6		)	48
Costs and Expenses:
Beginning inventory costs	44			—		8			—			52			(66		)	—			(7		)	—			(73		)	43			—		9			—			52			(66		)	(2		)	(17		)	—			(85		)
Total direct operating costs	369			26		53			83			531			(7		)	(7		)	(3		)	49			32			393			15		45			41			494			68			(7		)	—			(29		)	32
Total royalty/production taxes	50			3		7			—			60			(1		)	(1		)	(2		)	(1		)	(5		)	51			1		6			1			59			6			(1		)	(1		)	1			5
Total direct services to operations	60			4		6			36			106			(6		)	(2		)	1			(50		)	(57		)	65			3		7			46			121			6			(2		)	1			(19		)	(14		)
Total retirement and disability	43			3		6			5			57			(1		)	—			(2		)	2			(1		)	44			2		6			3			55			4			(1		)	(1		)	(6		)	(4		)
Depreciation, depletion and amortization	72			5		9			14			100			(5		)	(2		)	(2		)	10			1			79			3		11			11			104			12			(2		)	2			(4		)	8
Ending inventory costs	(43		)	—		(9		)	—			(52		)	67			—			17			—			84			(51		)	—		(7		)	—			(58		)	16			—			26			1			43
Total Costs and Expenses	595			41		80			138			854			(19		)	(12		)	2			10			(19		)	624			24		77			102			827			46			(15		)	10			(56		)	(15		)
Freight Expense	—			—		—			10			10			—			—			—			(39		)	(39		)	—			—		—			12			12			—			—			—			(15		)	(15		)
Total Costs	595			41		80			148			864			(19		)	(12		)	2			(29		)	(58		)	624			24		77			114			839			46			(15		)	10			(71		)	(30		)
Earnings (Loss) Before Income Taxes	$	104		$	17	$	31		$	(87	)	$	65		$	(30	)	$	(2	)	$	(12	)	$	(148	)	$	(192	)	$	129		$	6	$	21		$	(70	)	$	86		$	39		$	(4	)	$	(22	)	$	65		$	78

THERMAL COAL SEGMENT

The thermal coal segment contributed $~~104~~129 million to total Company earnings before income tax for the three months ended ~~June~~September 30, 2013 and $~~134~~90 million for the three months ended ~~June~~September 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:


	For the Three Months Ended June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	11.8		12.2		(0.4		)	(3.3	)%	12.8		10.8		2.0			18.5	%
Average Sales Price Per Thermal Ton Sold	$	59.39	$	61.47	$	(2.08	)	(3.4	)%	$	59.08	$	62.11	$	(3.03	)	(4.9	)%

Beginning Inventory Costs Per Thermal Ton	$	50.57	$	55.60	$	(5.03	)	(9.0	)%	$	55.36	$	56.03	$	(0.67	)	(1.2	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	31.60	$	30.96	$	0.64		2.1	%	$	30.38	$	32.24	$	(1.86	)	(5.8	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	4.26		4.18		0.08			1.9	%	3.91		4.46		(0.55		)	(12.3	)%
Total Direct Services to Operations Per Thermal Ton Produced	5.17		5.42		(0.25		)	(4.6	)%	5.06		5.87		(0.81		)	(13.8	)%
Total Retirement and Disability Per Thermal Ton Produced	3.68		3.62		0.06			1.7	%	3.43		4.04		(0.61		)	(15.1	)%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	6.20		6.36		(0.16		)	(2.5	)%	6.14		6.70		(0.56		)	(8.4	)%
Total Production Costs Per Thermal Ton Produced	$	50.91	$	50.54	$	0.37		0.7	%	$	48.92	$	53.31	$	(4.39	)	(8.2	)%

Ending Inventory Costs Per Thermal Ton	$	55.36	$	56.03	$	(0.67	)	(1.2	)%	$	52.26	$	51.55	$	0.71		1.4	%

Total Costs Per Thermal Ton Sold	$	50.60	$	50.50	$	0.10		0.2	%	$	49.07	$	53.81	$	(4.74	)	(8.8	)%
Average Margin Per Thermal Ton Sold	$	8.79	$	10.97	$	(2.18	)	(19.9	)%	$	10.01	$	8.30	$	1.71		20.6	%

Thermal coal revenue was $~~699~~753 million for the three months ended ~~June~~September 30, 2013 compared to $~~748~~667 million for the three months ended ~~June~~September 30, 2012. The $4986 million ~~decrease~~increase was attributable to a 2.0 million increase in tons sold offset, in part, by a $~~2.08~~3.03 per ton lower average sales ~~price and~~ ~~0.4~~ ~~million reduction in tons sold.~~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 ~~reduction~~increase in sales tons was ~~partially~~primarily due to the ~~Blacksville No. 2 Mine being idled for most~~July 27, 2012 structural failure of the ~~quarter as a result of~~above-ground conveyor system at the ~~mine fire that~~Bailey Preparation Plant which resulted in fewer tons in the 2012 period. The decrease in price was ~~previously discussed. Also, 0.5~~partially offset by 0.9 million tons of thermal coal ~~were~~being priced on the export market at an average sales price of ~~$68.68~~$63.74 per ton for the three months ended ~~June~~September 30, 2013 compared to ~~2.3~~0.8 million tons at an average price of ~~$55.09~~$61.93 per ton for the three months ended ~~June~~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 ~~are~~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 $~~595~~624 million for the three months ended ~~June~~September 30, 2013, or $1946 million ~~lower~~higher than the $~~614~~578 million for the three months ended ~~June~~September 30, 2012. Total cost of goods sold for thermal coal was $~~50.60~~49.07 per ton in the three months ended ~~June~~September 30, 2013 compared to $~~50.50~~53.81 per ton in the three months ended ~~June~~September 30, 2012. The ~~decrease~~increase in total dollars and ~~increase~~decrease in unit costs per thermal ton ~~produced~~ was primarily due to the increase in tons sold. The items described ~~below.~~below also had an impact on cost of goods sold.

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.

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

~~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.~~

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.

Royalties and production taxes were $5051 million, or ~~improved~~impaired $16 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 ~~primarily~~ to ~~the shutdown of the Fola Mining Complex~~higher production tons, although higher production tons resulted in ~~August 2012, as previously discussed.~~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 ~~$60~~$65 million in the current period compared to ~~$66~~$59 million in the prior period. Direct services to the operations were ~~$5.17~~$5.06 per ton produced in the current period compared to ~~$5.42~~$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-retirement~~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 ~~$43~~$44 million for the three months ended ~~June~~September 30, 2013 compared to ~~$44~~$40 million for the three months ended ~~June~~September 30, 2012. The ~~decrease~~increase in ~~the~~ 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-retirement~~post-employment benefit plan that occurred after ~~June~~September 30, 2012. These ~~improvements~~impairments were offset, in part, by the ~~reduction~~increase in production ~~volumes~~tons which ~~negatively impacted~~had a positive impact on unit costs.

Depreciation, depletion and amortization for the thermal coal segment was ~~$72~~$79 million for the three months ended ~~June~~September 30, 2013 compared to ~~$77~~$67 million for the three months ended ~~June~~September 30, 2012. ~~Unit costs per thermal ton produced were lower in the three months ended~~ The $~~June 30, 2013~~12 million ~~compared to the three months ended~~ ~~June 30, 2012~~increase was due to ~~production being halted at the Blacksville No. 2 Mine for most of the 2013 period due~~higher depletion directly related to ~~the fire. This resulted in no amortization or depletion expense for that period.~~higher tons produced. Unit ~~costs~~cost were ~~also~~ improved due to ~~the idling~~higher volumes produced, which allows for cost of ~~the Fola Mining Complex in 2012.~~straight-line depreciation to be spread over additional volumes.

Changes in thermal coal inventory volumes and carrying value resulted in $1an $8 million ofdecrease in cost of goods sold in the three months ended ~~June~~September 30, 2013 and ~~had no impact~~a $42 million increase in cost of goods sold in the three months ended ~~June~~September 30, 2012. Thermal coal inventory was ~~0.8~~1.0 million tons at ~~June~~September 30, 2013 compared to ~~2.0~~1.3 million tons at ~~June~~September 30, 2012.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $176 million to total Company earnings before income tax for the three months ended ~~June~~September 30, 2013 compared to $1910 million for the three months ended ~~June~~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 Three Months Ended June 30,
2013 2012 Variance
Percent
Change
Company Produced High Vol Met Tons Sold (in millions) 0.9
1.2
(0.3 ) (25.0 )%
Average Sales Price Per High Vol Met Ton Sold $ 62.50
$ 59.94
$ 2.56
4.3 %

Beginning Inventory Costs Per High Vol Met Ton $ —
$ —
$ —
— %

Total Direct Operating Costs Per High Vol Met Ton Produced $ 29.12
$ 27.88
$ 1.24
4.4 %
Total Royalty/Production Taxes Per High Vol Met Ton Produced 2.88
3.01
(0.13 ) (4.3 )%
Total Direct Services to Operations Per High Vol Met Ton Produced 4.53
4.85
(0.32 ) (6.6 )%
Total Retirement and Disability Per High Vol Met Ton Produced 2.86
2.74
0.12
4.4 %
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced 5.62
6.46
(0.84 ) (13.0 )%
     Total Production Costs Per High Vol Met Ton Produced $ 45.01
$ 44.94
$ 0.07
0.2 %

Ending Inventory Costs Per High Vol Met Ton $ —
$ —
$ —
— %

     Total Costs Per High Vol Met Ton Sold $ 45.01
$ 44.94
$ 0.07
0.2 %
     Margin Per High Vol Met Ton Sold $ 17.49
$ 15.00
$ 2.49
16.6 %



	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 $5830 million for the three months ended ~~June~~September 30, 2013 compared to $7248 million ~~million~~ for the three months ended ~~June~~September 30, 2012. Average sales prices for high volatile metallurgical coal ~~increased $2.56~~decreased $7.34 per ton in athe period-to-period comparison. CONSOL Energy priced ~~0.8~~0.5 million tons of high volatile metallurgical coal in the export market at an average sales price of ~~$60.83~~$60.42 per ton for the three months ended ~~June~~September 30, 2013 compared to ~~1.1~~0.6 million tons at an average price of ~~$57.30~~$65.96 per ton for the three months ended ~~June~~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 $4124 million for the three months ended ~~June~~September 30, 2013, or $1215 million lower than the $5339 million for the three months ended ~~June~~September 30, 2012. Total cost of goods sold for high volatile metallurgical coal was ~~$45.01~~$47.25 per ton in the three months ended ~~June~~September 30, 2013 compared to ~~$44.94~~$55.29 per ton in the three months ended ~~June~~September 30, 2012. The ~~increase~~decrease in ~~cost of goods sold~~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 $2615 million in the three months ended ~~June~~September 30, 2013 compared to $3322 million in the three months ended ~~June~~September 30, 2012. Direct operating costs were $~~29.12~~29.85 per ton produced in the current period compared to $~~27.88~~30.10 per ton produced in the prior period. ~~The increase~~Changes in the average direct operating costs per ton for high volatile metallurgical ~~ton produced~~coal sold were primarily related to ~~fewer~~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. Fixed costs are allocated over less tons, resulting in higher~~produced which negatively impacted unit costs.

Royalties and production taxes were $31 million or improved $1 million in the current period ~~due~~ primarily related to the ~~shutdown~~mix of mines which sold on the high volatile metallurgical coal market. Mines with higher royalty rates produced a larger portion of the ~~Fola Mining Complex~~high volatile metallurgical coal shipped in ~~August 2012, as previously discussed.~~the prior period compared to the current period.

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 $4$3 million in the current period compared to $6$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 $~~4.53~~5.21 per ton produced in the current period compared to $~~4.85~~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 $3$2 million for the three months ended ~~June~~September 30, 2013 ~~and~~ compared to $~~June~~3 million in the three months ended September 30, 2012. ~~Even though~~The decrease in total high volatile metallurgical coal retirement and disability total dollars ~~remained consistent,~~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 ~~volumes.~~tons produced.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $5$3 million for the three months ended ~~June~~September 30, 2013 compared to $7$5 million in the three months ended ~~June~~September 30, 2012. ~~Unit costs per high volatile ton produced were lower in the three months ended~~ ~~June 30, 2013~~ ~~compared to the three months ended~~ ~~June 30, 2012~~The decrease was primarily due to ~~the shutdown of the Fola Mining Complex in August 2012.~~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 ~~June~~September 30, 2013 and ~~June~~September 30, 2012. There was no high volatile metallurgical coal inventory at ~~June~~September 30, 2013 or ~~June~~September 30, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $3121 million to total Company earnings before income tax in the three months ended ~~June~~September 30, 2013 compared to $43 million in the three months ended ~~June~~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 June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	1.1		1.0		0.1			10.0	%	1.1		0.8		0.3			37.5	%
Average Sales Price Per Low Vol Met Ton Sold	$	97.54	$	123.71	$	(26.17	)	(21.2	)%	$	85.77	$	135.66	$	(49.89	)	(36.8	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	85.60	$	72.97	$	12.63		17.3	%	$	64.76	$	69.84	$	(5.08	)	(7.3	)%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	44.31	$	48.66	$	(4.35	)	(8.9	)%	$	41.07	$	55.61	$	(14.54	)	(26.1	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.97		8.10		(2.13		)	(26.3	)%	5.16		8.75		(3.59		)	(41.0	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	4.90		4.50		0.40			8.9	%	5.98		6.83		(0.85		)	(12.4	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.56		7.00		(1.44		)	(20.6	)%	5.57		8.63		(3.06		)	(35.5	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	7.90		9.51		(1.61		)	(16.9	)%	9.55		11.29		(1.74		)	(15.4	)%
Total Production Costs Per Low Vol Met Ton Produced	$	68.64	$	77.77	$	(9.13	)	(11.7	)%	$	67.33	$	91.11	$	(23.78	)	(26.1	)%

Ending Inventory Costs Per Low Vol Met Ton	$	64.76	$	69.84	$	(5.08	)	(7.3	)%	$	65.42	$	87.32	$	(21.90	)	(25.1	)%

Total Costs Per Low Vol Met Ton Sold	$	70.46	$	79.80	$	(9.34	)	(11.7	)%	$	67.18	$	83.09	$	(15.91	)	(19.1	)%
Margin Per Low Vol Met Ton Sold	$	27.08	$	43.91	$	(16.83	)	(38.3	)%	$	18.59	$	52.57	$	(33.98	)	(64.6	)%

Low volatile metallurgical coal revenue was $~~111~~98 million for the three months ended ~~June~~September 30, 2013 compared to $~~121~~110 million for the three months ended ~~June~~September 30, 2012. The $1012 million decrease was attributable to a ~~$26.17~~$49.89 per ton lower average sales price and was partially offset by a ~~0.1~~0.3 million increase in tons sold. Average sales prices for low volatile

metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal ~~demand.~~market. For the 2013 period, ~~0.8~~0.9 million tons of low volatile metallurgical coal were priced on the export market at an average price of ~~$89.02~~$79.06 per ton compared to ~~0.8~~0.6 million tons at an average price of ~~$107.72~~$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 ~~$80~~$77 million for the three months ended ~~June~~September 30, 2013, or $2$10 million higher than the ~~$78~~$67 million for the three months ended ~~June~~September 30, 2012. Total cost of goods sold for low volatile metallurgical coal was ~~$70.46~~$67.18 per ton in the three months ended ~~June~~September 30, 2013 compared to ~~$79.80~~$83.09 per ton in the three months ended ~~June~~September 30, 2012. The increase in total dollars and decrease in ~~cost of goods sold~~unit costs per low volatile metallurgical ton was due to the ~~following~~ 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 ~~$53~~$45 million in the three months ended ~~June~~September 30, 2013 ~~compared to $56 million in the three months ended~~and ~~June~~September 30, 2012. Direct operating costs improved primarily due to a five-day work schedule being implemented in the 2013 period at the Buchanan Mine and due to a decrease in contract mining fees resulting from the idling of the Amonate Complex in September 2012. Direct operating costs were ~~$44.31~~$41.07 per ton produced in the current period compared to ~~$48.66~~$55.61 per ton produced in the prior period. ~~Low volatile metallurgical coal~~The $14.54 improvement in unit costs is directly related to the increase in production ~~was 1.2 million~~tons. Production tons are higher in the ~~three months ended~~ ~~June 30, 2013~~ ~~compared~~current period due to ~~1.1 million tons~~the Buchanan Mine being idled in September 2012 in response to the ~~three months ended~~ ~~June 30, 2012~~.weak world economy.

Royalties and production taxes were $7$6 million, or improved $2$1 million in the current period, compared to $9$7 million in the prior period. Unit costs were also improved ~~$2.13~~$3.59 per low volatile metallurgical ton produced to ~~$5.97~~$5.16 per ton produced in the current period compared to ~~$8.10~~$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 ~~lower~~the $49.89 decrease in average sales ~~prices.~~price, which is the basis for most royalties and production taxes.

operations for low volatile metallurgical coal were ~~$4.90~~$5.98 per ton produced in the current period compared to ~~$4.50~~$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-retirement~~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$6 million for the three months ended ~~June~~September 30, 2013 compared to $8$7 million for the three months ended ~~June~~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-retirement~~post-employment benefit plan that occurred on ~~June~~September 30, 2012. This, coupled with the increase in ~~volumes,~~production tons, resulted in an improvement on the unit costs of ~~$1.44~~$3.06 in the period-to-period comparison.

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

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in ~~a decrease~~an increase of $1$2 million to cost of goods sold in the three months ended ~~June~~September 30, 2013 and ~~an increase~~a decrease of ~~$10~~$7 million to cost of goods sold in the three months ended ~~June~~September 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at ~~June~~September 30, 2013 compared to ~~0.3~~0.4 million tons at ~~June~~September 30, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $8770 million for the three months ended ~~June~~September 30, 2013 compared to ~~earnings~~a loss before income tax of $61135 million for the three months ended ~~June~~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 ~~less than~~ 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the three months ended ~~June~~September 30, 2012. No coal was recovered during the reclamation process at idled facilities for the three months ended ~~June~~September 30, 2013. The primary focus of the activity atthese 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 $5$7 million for the three months ended ~~June~~September 30, 2013 compared to $3$5 million for the three months ended ~~June~~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 ~~$10~~$12 million for the three months ended ~~June~~September 30, 2013 compared to ~~$49~~$27 million for the three months ended ~~June~~September 30, 2012. The ~~$39~~$15 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $4625 million for the three months ended ~~June~~September 30, 2013 compared to $~~184~~18 million for the three months ended ~~June~~September 30, 2012. The change is due to the following items:

Gain on sale of assets attributable to the Other Coal segment ~~were $26~~was $18 million in the three months ended ~~June~~September 30, 2013 compared to ~~$163~~$1 million in the three months ended ~~June~~September 30, 2012. The ~~decrease~~increase of ~~$137~~$17 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 the coal lands and surface rights in southern West Virginia that resulted in income of $11 million. This is offset, in part, by the 2013 sale of ~~Potomac coal reserves~~1.5 MM tons of Pittsburgh 8 Coal that ~~resulted~~CONSOL Energy controlled in ~~income~~Belmont County, OH for a gain of ~~$25~~$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. ~~The remaining change was related to various transactions that occurred throughout both periods, none of which were individually material.~~

Equity in earnings of affiliates ~~increased $6~~decreased $3 million due to ~~higher~~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 $7$2 million decrease is due to various items, none of which are individually significant.

Other coal segment total costs were $~~148~~114 million for the three months ended ~~June~~September 30, 2013 compared to $~~177~~185 million for the three months ended ~~June~~September 30, 2012. The decrease of $2971 million was primarily due to the following items:

For the Three Months Ended June 30,
2013 2012 Variance
Blacksville No. 2 Mine Fire $ 23
$ —
$ 23
Purchased Coal 10
7
3
Stock-based compensation 8
7
1
Closed and idle mines 38
50
(12 )
Freight expense 10
49
(39 )
Other 59
64
(5 )
Total Other Coal Segment Costs $ 148
$ 177
$ (29 )



	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	)

~~The Blacksville No. 2 Mine fire expense was due~~Bailey Belt Incident costs represent expenses during the belt-reconstruction period related 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 recovery has not been reflected in the three months ended ~~June 30, 2013~~.

~~Purchased coal costs increased due to higher amounts of coal that needed to be 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 executive compensation award programs. The compensation expensecontinued advancement of the ~~CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.~~

~~Closed~~mines and ~~idle mine costs decreased approximately $12 million for the three months ended~~ ~~June 30, 2013~~ ~~compared to the three months ended~~ ~~June 30, 2012. There was a $24 million decrease in asset retirement obligations. This was primarily due to an increase in the reclamation liability~~on-going projects at the Fola Mining Complex in the June 2012 period due to new regulatory requirements, and water and selenium treatment estimates. The decrease was offset, in part, by an increase of $7 million due to the idling of the Fola Mining Complex in August 2012, and an increase of $2 million due to the idling of the Amonate Complex in September 2012. 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.~~

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 $5$9 million due to various transactions that occurred throughout both periods, none of which were individually material.

5354

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

The gas segment had a $52 million loss before income tax in the three months ended ~~June~~September 30, 2013 compared to earnings before income tax of $112 million in the three months ended ~~June~~September 30, 2012.


	For the Three Months Ended													Difference to Three Months Ended														For the Three Months Ended													Difference to Three Months Ended
	June 30, 2013													June 30, 2012														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			CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	88	$	34		$	47	$	3		$	172		$	—		$	—		$	23	$	1		$	24		$	83	$	33		$	72	$	4		$	192		$	(11	)	$	1		$	36	$	2		$	28
Related Party	1		—			—		—			1			—			—			—		—			—			1		—			—		—			1			—			—			—		—			—
Total Outside Sales	89		34			47		3			173			—			—			23		1			24			84		33			72		4			193			(11		)	1			36		2			28
Gas Royalty Interest	—		—			—		17			17			—			—			—		7			7			—		—			—		15			15			—			—			—		2			2
Purchased Gas	—		—			—		1			1			—			—			—		1			1			—		—			—		2			2			—			—			—		1			1
Other Income	—		—			—		11			11			—			—			—		(7		)	(7		)	—		—			—		13			13			—			—			—		1			1
Total Revenue and Other Income	89		34			47		32			202			—			—			23		2			25			84		33			72		34			223			(11		)	1			36		6			32
Lifting	10		10			5		1			26			(1		)	(1		)	3		1			2			8		9			5		2			24			(1		)	(1		)	2		2			2
Ad Valorem, Severance, and Other Taxes	3		3			1		—			7			1			1			—		—			2			3		2			3		—			8			1			—			2		(2		)	1
Gathering	29		9			10		1			49			3			4			5		—			12			28		7			11		1			47			1			1			4		—			6
Gas Direct Administrative, Selling & Other	2		2			7		1			12			(2		)	(2		)	5		(1		)	—			2		2			6		2			12			(1		)	(1		)	—		3			1
Depreciation, Depletion and Amortization	23		15			12		2			52			1			1			3		—			5			22		15			19		2			58			(1		)	1			6		—			6
General & Administration	—		—			—		12			12			—			—			—		3			3			—		—			—		12			12			—			—			—		2			2
Gas Royalty Interest	—		—			—		14			14			—			—			—		7			7			—		—			—		13			13			—			—			—		2			2
Purchased Gas	—		—			—		1			1			—			—			—		—			—			—		—			—		1			1			—			—			—		—			—
Exploration and Other Costs	—		—			—		10			10			—			—			—		(6		)	(6		)	—		—			—		23			23			—			—			—		16			16
Other Corporate Expenses	—		—			—		22			22			—			—			—		5			5			—		—			—		25			25			—			—			—		9			9
Interest Expense	—		—			—		2			2			—			—			—		1			1			—		—			—		2			2			—			—			—		1			1
Total Cost	67		39			35		66			207			2			3			16		10			31			63		35			44		83			225			(1		)	—			14		33			46
Earnings Before Income Tax	$	22	$	(5	)	$	12	$	(34	)	$	(5	)	$	(2	)	$	(3	)	$	7	$	(8	)	$	(6	)	$	21	$	(2	)	$	28	$	(49	)	$	(2	)	$	(10	)	$	1		$	22	$	(27	)	$	(14	)

5455

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $2221 million to the total Company earnings before income tax for the three months ended ~~June~~September 30, 2013 compared to $2431 million for the three months ended ~~June~~September 30, 2012.


	For the Three Months Ended June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	20.8		22.3		(1.5		)	(6.7	)%	21.0		21.7		(0.7		)	(3.2	)%
Average CBM sales price per thousand cubic feet sold	$	4.26	$	3.96	$	0.30		7.6	%	$	3.99	$	4.36	$	(0.37	)	(8.5	)%
Average CBM lifting costs per thousand cubic feet sold	0.48		0.45		0.03			6.7	%	0.39		0.41		(0.02		)	(4.9	)%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.13		0.11		0.02			18.2	%	0.12		0.11		0.01			9.1	%
Average CBM gathering costs per thousand cubic feet sold	1.40		1.17		0.23			19.7	%	1.31		1.26		0.05			4.0	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.10		0.18		(0.08		)	(44.4	)%	0.11		0.11		—			—	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.09		0.96		0.13			13.5	%	1.06		1.04		0.02			1.9	%
Total Average CBM costs per thousand cubic feet sold	3.20		2.87		0.33			11.5	%	2.99		2.93		0.06			2.0	%
Average Margin for CBM	$	1.06	$	1.09	$	(0.03	)	(2.8	)%	$	1.00	$	1.43	$	(0.43	)	(30.1	)%

CBM sales revenues were $8984 million in the three months ended ~~June~~September 30, 2013 and ~~2012. The~~ ~~6.7%~~$95 ~~decrease in~~million for the three months ended September 30, 2012. Sales volumes ~~sold was offset by a~~decreased ~~7.6%~~3.2% ~~increase in~~and the average sales price decreased 8.5% per thousand cubic feet sold. The ~~increase~~decrease in CBM average sales price was the result of ~~higher average~~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 ~~11.6~~13.8 billion cubic feet of our produced CBM gas sales volumes for the three months ended ~~June~~September 30, 2013 at an average price of ~~$4.58~~$4.49 per thousand cubic feet. For the three months ended ~~June~~September 30, 2012, these financial hedges represented ~~10.9~~11.4 billion cubic feet at an average price of ~~$5.33~~$5.34 per thousand cubic feet. CBM sales volumes decreased ~~1.5~~0.7 billion cubic feet for the three months ended ~~June~~September 30, 2013 compared to the 2012 period primarily due to normal well declines ~~without a corresponding increase in~~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 $6763 million for the three months ended ~~June~~September 30, 2013 compared to $6564 million for the three months ended ~~June~~September 30, 2012. The decrease in total dollars and increase in ~~total~~unit costs for the CBM segment are due to the following items:

•CBM lifting costs were $108 million for the three months ended ~~June~~September 30, 2013 compared to $119 million for the three months ended ~~June~~September 30, 2012. The decrease in total dollars and ~~the~~ ~~$0.03~~ ~~per thousand cubic feet increase in average lifting~~ unit costs ~~are both directly related~~was primarily due to lower road maintenance and lower contractor services in the ~~decreased sales~~period-to-period comparison. The impact of lower expenses on unit costs was offset, in part, by lower volumes ~~as discussed above.~~sold.

•CBM ad valorem, severance and other taxes were $3 million for the three months ended ~~June~~September 30, 2013 compared to $2 million for the three months ended ~~June~~September 30, 2012. The $1 ~~million~~ increase in total dollars and unit costs was primarily due to ~~increased~~an increase in severance tax expense ~~due to higher~~caused by an increase in the average gas sales ~~prices. The~~ ~~$0.02~~ ~~per thousand cubic feet increase in unit costs is primarily due to~~price, without the ~~higher average gas sales prices and decrease in sales volumes.~~impact of hedging, as described above.

•CBM gathering costs were $2928 million for the three months ended ~~June~~September 30, 2013 compared to $2627 million for the three months ended ~~June~~September 30, 2012. The $1 million increase and $~~0.23~~0.05 ~~per thousand cubic feet~~ increase in average ~~CBM gathering~~per unit costs ~~are related~~were due to increased ~~power~~transportation costs, ~~due to higher utility rates,~~ increased pipeline maintenance, and increased road ~~maintenance and lower volumes sold~~maintenance. Unit costs were also negatively impacted by the reduction in ~~the period-to-period comparison.~~sales volumes.

•CBM direct administrative, selling & other costs ~~for the CBM segment~~ were $2 million for the three months ended ~~June~~September 30, 2013 compared to $43 million for the three months ended ~~June~~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 reduction in volumes.~~

5556

•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 ~~June 30, 2013~~ ~~compared to~~ ~~$22~~ ~~million for the~~ ~~three months~~ ~~ended~~ ~~June~~September 30, 2012. There was approximately ~~$16~~$15 million, or ~~$0.76~~$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 ~~June~~September 30, 2013. The production portion of depreciation, depletion and amortization was $15 million, or ~~$0.67~~$0.68 per unit-of-production in the three months ended ~~June~~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 ~~June~~September 30, 2013. The non-production related depreciation, depletion and amortization was $7$8 million, or ~~$0.29~~$0.35 per thousand cubic feet for the three months ended ~~June~~September 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $52 million for the three months ended ~~June~~September 30, 2013 compared to a loss before income tax of $23 million for the three months ended ~~June~~September 30, 2012.


	For the Three Months Ended June 30,											For the Three Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	6.7			7.2			(0.5		)	(6.9	)%	6.8			7.0			(0.2		)	(2.9	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	5.00		$	4.74		$	0.26		5.5	%	$	4.85		$	4.59		$	0.26		5.7	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.46			1.46			—			—	%	1.36			1.44			(0.08		)	(5.6	)%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.43			0.30			0.13			43.3	%	0.27			0.37			(0.10		)	(27.0	)%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.35			0.77			0.58			75.3	%	1.01			0.87			0.14			16.1	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.34			0.53			(0.19		)	(35.8	)%	0.37			0.35			0.02			5.7	%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.25			2.01			0.24			11.9	%	2.15			2.05			0.10			4.9	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.83			5.07			0.76			15.0	%	5.16			5.08			0.08			1.6	%
Average Margin for Shallow Oil and Gas	$	(0.83	)	$	(0.33	)	$	(0.50	)	(151.5	)%	$	(0.31	)	$	(0.49	)	$	0.18		36.7	%

Shallow Oil and Gas sales revenues were $3433 million for ~~both~~ the three months ended ~~June~~September 30, 2013 ~~and 2012.~~compared to $32 million for the three months ended September 30, 2012. The ~~6.9%~~2.9% decrease in volumes sold was offset, in part, by a ~~5.5%~~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 ~~3.6~~3.8 billion cubic feet of our produced shallow oil and gas sales volumes for the three months ended ~~June~~September 30, 2013 at an average price of ~~$5.21~~$5.16 per thousand cubic feet. For the three months ended ~~June~~September 30, 2012, these financial hedges represented ~~5.4~~4.9 billion cubic feet at an average price of ~~$5.25~~$5.23 per thousand cubic feet.

Total costs for the shallow oil and gas segment were $3935 million for the three months ended ~~June~~September 30, 2013 ~~compared to~~and ~~$36~~ ~~million for the~~ ~~three months~~ ~~ended~~ ~~June 30,~~ 2012. The $0.08increase in ~~total~~ costs per thousand cubic feet sold for the shallow oil and gas segment ~~are~~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 ~~June 30, 2013~~ ~~compared to~~ ~~$11~~ ~~million for the~~ ~~three months~~ ~~ended~~ ~~June~~September 30, 2012. The $1 million decrease toin 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 ~~average~~impact of the decrease on unit costs ~~remained consistent in the period-to-period comparison due to the decrease in~~was offset by lower sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes were $3 ~~million for the~~ ~~three months~~ ~~ended~~ ~~June 30, 2013~~ ~~and~~ $2 million for the three months ended ~~June~~September 30, ~~2012. The $~~12013 ~~million increase in total costs was primarily due to higher average sales prices during the current period. The~~ ~~$0.13~~ ~~per thousand cubic feet increase in average unit costs is primarily due to the higher average sales prices~~ and ~~decreased sales volumes.~~2012.

5657

•Shallow Oil and Gas gathering costs were $97 million for the three months ended ~~June~~September 30, 2013 compared to $56 million for the three months ended ~~June~~September 30, 2012. Gathering costs increased $41 million primarily due to ~~increased~~an increase in firm transportation ~~costs and higher compressor repair and maintenance~~ 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 ~~June~~September 30, 2013 compared to $43 million for the three months ended ~~June~~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 $21 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~~was offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization costs were $15 million for the three months ended ~~June~~September 30, 2013 compared to $14 million for the three months ended ~~June~~September 30, 2012. There was approximately $13 million, or ~~$1.98~~$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 ~~June~~September 30, 2013. There was approximately $12 million, or ~~$1.77~~$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 ~~June~~September 30, 2012. There was approximately $2 million, or ~~$0.27~~$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 ~~June~~September 30, 2013~~. There was $2 million, or $0.24 per thousand cubic feet, of depreciation, depletion~~ and ~~amortization related to gathering and other equipment that is reflected on a straight-line basis for the~~ ~~three months~~ ~~ended~~ ~~June 30, 2012~~.2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $1228 million to the total Company earnings before income tax for the three months ended ~~June~~September 30, 2013 compared to $56 million for the three months ended ~~June~~September 30, 2012.


	For the Three Months Ended June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	10.4		7.2		3.2			44.4	%	17.4		10.1		7.3			72.3	%
Average Marcellus sales price per thousand cubic feet sold	$	4.49	$	3.28	$	1.21		36.9	%	$	4.16	$	3.58	$	0.58		16.2	%
Average Marcellus lifting costs per thousand cubic feet sold	0.44		0.28		0.16			57.1	%	0.29		0.32		(0.03		)	(9.4	)%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.15		0.13		0.02			15.4	%	0.17		0.12		0.05			41.7	%
Average Marcellus gathering costs per thousand cubic feet sold	0.95		0.64		0.31			48.4	%	0.66		0.68		(0.02		)	(2.9	)%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.63		0.27		0.36			133.3	%	0.34		0.55		(0.21		)	(38.2	)%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.19		1.29		(0.10		)	(7.8	)%	1.09		1.28		(0.19		)	(14.8	)%
Total Average Marcellus costs per thousand cubic feet sold	3.36		2.61		0.75			28.7	%	2.55		2.95		(0.40		)	(13.6	)%
Average Margin for Marcellus	$	1.13	$	0.67	$	0.46		68.7	%	$	1.61	$	0.63	$	0.98		155.6	%

The Marcellus segment sales revenues were $4772 million for the three months ended ~~June~~September 30, 2013 compared to $2436 million for the three months ended ~~June~~September 30, 2012. The $2336 million increase is primarily due to a ~~44.4%~~72.3% increase in volumes sold, and a ~~36.9%~~16.2% increase in average sales ~~prices~~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 ~~the improvement in general~~higher market prices and ~~sales~~an increase in the sale of natural gas liquids and condensate, offset by various gas swap transactions that matured in ~~the~~ ~~three months~~ ~~ended~~ ~~June 30, 2013~~.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 ~~4.5~~6.4 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended ~~June~~September 30, 2013 at an average price of ~~$4.74~~$4.62 per thousand cubic feet. For the three months ended ~~June~~September 30, 2012, these financial hedges represented ~~2.8~~3.0 billion cubic feet at an average price of ~~$4.95~~$4.97 per thousand cubic feet. ~~The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program.~~

Total costs for the Marcellus segment were $3544 million for the three months ended ~~June~~September 30, 2013 compared to $1930 million for the three months ended ~~June~~September 30, 2012. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

5758

•Marcellus lifting costs were $5 million for the three months ended ~~June~~September 30, 2013 compared to $23 million for the three months ended ~~June~~September 30, 2012. The$2 million increase primarily relates to increased road maintenance costs ~~increased salt water disposal costs,~~ and increased ~~accretion expense on the~~ well ~~plugging liability.~~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 ~~June~~September 30, ~~2013~~2012 ~~and 2012.~~. The increase in ~~average~~total dollars and unit costs ~~was~~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 $1011 million for the three months ended ~~June~~September 30, 2013 compared to $57 million for the three months ended ~~June~~September 30, 2012. ~~Average gathering~~Total dollars and unit costs increased~~$0.31~~ ~~per unit primarily~~ 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 $76 million for the three months ended ~~June~~September 30, 2013 ~~compared to~~ $2 ~~million for the~~ ~~three months~~ ~~ended~~ ~~June 30, 2012~~.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 direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of total natural gas volumes sold. The impact on average unit costs from the increase in direct administrative costs was partially offset by higher volumes sold.

•Depreciation, depletion and amortization costs were $1219 million for the three months ended ~~June~~September 30, 2013 compared to $913 million for the three months ended ~~June~~September 30, 2012. There was approximately ~~$12~~$19 million, or ~~$1.18~~$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 ~~June~~September 30, 2013. There was approximately $8$12 million, or ~~$1.14~~$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 ~~June~~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 ~~June~~September 30, 2013. There was $1 million, or ~~$0.15~~$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 ~~June~~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 $34 million for the three months ended ~~June~~September 30, 2013 and $2 million for the three months ended ~~June~~September 30, 2012. Total costs related to these other sales were $57 million for the three months ended ~~June~~September 30, 2013 ~~and~~compared to ~~June~~$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 $1715 million for the three months ended ~~June~~September 30, 2013 compared to $1013 million for the three months ended ~~June~~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 June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.9		4.2		(0.3		)	(7.1	)%	3.5		4.8		(1.3		)	(27.1	)%
Average Sales Price Per thousand cubic feet	$	4.31	$	2.26	$	2.05		90.7	%	$	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 ~~June 30, 2013~~ ~~and less than $1 million for the~~ ~~three months~~ ~~ended~~ ~~June~~September 30, 2012.

5859


	For the Three Months Ended June 30,								For the Three Months Ended September 30,
	2013		2012		Variance		Percent Change		2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.4		0.3		0.1		33.3	%	0.3		0.2		0.1		50.0	%
Average Sales Price Per thousand cubic feet	$	3.96	$	2.39	$	1.57	65.7	%	$	5.14	$	3.29	$	1.85	56.2	%

Other income was $1113 million for the three months ended ~~June~~September 30, 2013 compared to $1812 million for the three months ended ~~June~~September 30, 2012. The $71 million change was primarily due to the following items:

~~Interest income~~There was an increase of $3 million related to ~~the notes receivable~~increased earnings from ~~the Noble joint venture transaction decreased $4 million due to the payment of the first note in September 2012.~~our equity affiliates.

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

~~There was a decrease~~Interest income decreased $4 million due to the collection of ~~$1 million in various other transactions, none of which are individually material.~~the final installment on the notes receivable from the Noble joint venture transaction.

General and ~~administrative~~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 ~~June~~September 30, 2013 compared to $910 million for the three months ended ~~June~~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 $1413 million for the three months ended ~~June~~September 30, 2013 compared to $711 million for the three months ended ~~June~~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 June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.9		4.2		(0.3		)	(7.1	)%	3.5		4.8		(1.3		)	(27.1	)%
Average Cost Per thousand cubic feet sold	$	3.43	$	1.69	$	1.74		103.0	%	$	3.66	$	2.18	$	1.48		67.9	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that ~~we sell.~~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 ~~June~~September 30, 2013 and 2012.


	For the Three Months Ended June 30,								For the Three Months Ended September 30,
	2013		2012		Variance		Percent Change		2013		2012		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.4		0.3		0.1		33.3	%	0.3		0.2		0.1			50.0	%
Average Cost Per thousand cubic feet sold	$	2.99	$	2.19	$	0.80	36.5	%	$	3.01	$	3.04	$	(0.03	)	(1.0	)%

Exploration and other costs were $1023 million for the three months ended ~~June~~September 30, 2013 compared to $167 million for the three months ended ~~June~~September 30, 2012. The $616 million ~~decrease~~increase is due to the following items:


	For the Three Months Ended June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance		Percent Change
Marcellus Title Defects	$	2	$	—	$	2		100	%	$	13	$	2	$	11	550.0	%
Lease Expiration Costs										3		1		2		200.0	%
Exploration	5		5		—			—	%	7		4		3		75.0	%
Lease Expiration Costs	3		11		(8		)	(72.7	)%
Total Exploration and Other Costs	$	10	$	16	$	(6	)	(37.5	)%	$	23	$	7	$	16	228.6	%

~~As part~~CONSOL Energy has substantially completed its review of the title defect ~~process the company is~~notice, asserted by Noble, and working ~~through~~in collaboration with ~~its joint venture partner,~~ Noble, ~~Energy, CONSOL Energy~~ 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.~~million for the three months ended September 30, 2012.

~~Exploration expenses remained consistent in the period-to-period comparison.~~

5960

Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $82 million ~~decrease~~increase is due to a greater number of leases which CONSOL Energy ~~allowing fewer leases~~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 $2225 million for the three months ended ~~June~~September 30, 2013 compared to $1716 million for the three months ended ~~June~~September 30, 2012. The $59 million increase in the period-to-period comparison was made up of the following items:


	For the Three Months Ended June 30,									For the Three Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Unutilized firm transportation	$	9	$	3	$	6		200	%	$	12	$	4	$	8		200.0	%
Short term incentive compensation										7		5		2			40.0	%
Stock-based compensation	5		4		1			25	%	4		4		—			—	%
Bank fees	2		2		—			—	%	2		2		—			—	%
Short term incentive compensation	4		7		(3		)	(42.9	)%
Other	2		1		1			100	%
Legal fees										—		1		(1		)	(100.0	)%
Total Other Corporate Expenses	$	22	$	17	$	5		29.4	%	$	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.~~increase, as well as additional processing capacity for natural gas liquids. The $68 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. 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.

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

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~~higher for the 2013 period compared to the 2012 period due to ~~the~~higher projected ~~lower~~ payouts.

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

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

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

Interest expense related to the gas segment was $2 million for the three months ended ~~June~~September 30, 2013 compared to $1 million for the three months ended ~~June~~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 ended ~~June~~September 30, 2013 compared to the three months ended ~~June~~September 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 $5872 million for the three months ended ~~June~~September 30, 2013 compared to a loss before income tax of $4553 million for the three months ended ~~June~~September 30, 2012. The other segment also includes total Company income tax expense of $1575 million for the three months ended ~~June~~September 30, 2013 compared to an income tax benefit of $5920 million for the three months ended ~~June~~September 30, 2012.

6061


	For the Three Months Ended June 30,											For the Three Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Sales—Outside	$	83		$	96		$	(13	)	(13.5	)%	$	79		$	88		$	(9	)	(10.2	)%
Other Income	3			3			—			—	%	5			3			2			66.7	%
Total Revenue	86			99			(13		)	(13.1	)%	84			91			(7		)	(7.7	)%
Cost of Goods Sold and Other Charges	81			81			—			—	%	94			82			12			14.6	%
Depreciation, Depletion & Amortization	7			6			1			16.7	%	6			6			—			—	%
Taxes Other Than Income Tax	3			2			1			50.0	%	2			3			(1		)	(33.3	)%
Interest Expense	53			55			(2		)	(3.6	)%	54			53			1			1.9	%
Total Costs	144			144			—			—	%	156			144			12			8.3	%
Loss Before Income Tax	(58		)	(45		)	(13		)	28.9	%	(72		)	(53		)	(19		)	35.8	%
Income Tax	15			59			(44		)	(74.6	)%	75			(20		)	95			475.0	%
Net Loss	$	(73	)	$	(104	)	$	31		29.8	%	$	(147	)	$	(33	)	$	(114	)	(345.5	)%

Industrial supplies:

Outside Sales from industrial supplies ~~was~~were $54 million for the three months ended ~~June~~September 30, 2013 compared to $6458 million for the three months ended ~~June~~September 30, 2012. The decrease of ~~$10~~$4 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $53 million for the three months ended ~~June~~September 30, 2013 compared to $6256 million for the three months ended ~~June~~September 30, 2012. The decrease of $9$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 ~~was~~were $2925 million for the three months ended ~~June~~September 30, 2013 compared to $3230 million for the three months ended ~~June~~September 30, 2012. The decrease of $3$5 million was primarily attributable to decreased thru-put ~~at the CNX Marine Terminal offset, in part, by higher~~as well as lower per ton thru-put ~~rates.~~rates for the quarter.

Total costs related to the transportation operations were $2524 million for the three months ended ~~June~~September 30, 2013 compared to $2122 million for the three months ended ~~June~~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 ~~of $4 million was~~is due to various items in both periods, none of which were individually material.

~~Miscellaneous other:~~

~~Additional other income remained consistent at~~Other corporate costs were $379 million for the three months ended ~~June~~September 30, 2013 ~~and~~ ~~June 30, 2012~~.

~~Other corporate costs were~~compared to $66 million for the three months ended ~~June 30, 2013~~ ~~compared to~~ ~~$61~~ ~~million for the three months ended~~ ~~June~~September 30, 2012. Other corporate costs increased due to the following items:

For the Three Months Ended June 30,
2013 2012 Variance
Pension settlement $ 5
$ —
$ 5
Bank fees 4
3
1
Interest expense 53
56
(3 )
Other 4
2
2
$ 66
$ 61
$ 5



	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

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 ~~adjustment is~~expenses were required when the ~~acceleration of unrecognized actuarial losses due to~~ lump sum ~~payments from~~distributions made for the ~~pension~~2013 plan ~~exceeding~~year exceeded the ~~annual projected~~total of the service and interest costs offor the ~~plan.~~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 $31 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~~ $2 ~~million due to various transactions that occurred throughout both periods, none of which were individually material.~~remained consistent in the period-to-period comparsion.

Income Taxes:

The effective income tax rate was ~~808.3%~~705.7% for the three months ended ~~June~~September 30, 2013 compared to ~~27.8%~~63.4% for the three months ended ~~June~~September 30, 2012. The effective rates for the three months ended ~~June~~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 ~~relationship between~~$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, ~~and~~excluding gain on sales of assets, approaches breakeven without corresponding reductions in excess percentage depletion, ~~impacts the~~ effective tax ~~rate.~~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 June 30,											For the Three Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	2		$	212		$	(210	)	(99.2	)%	$	11		$	(31	)	$	42		(133.9	)%
Income Tax Expense	$	15		$	59		$	(44	)	(74.6	)%	$	75		$	(20	)	$	95		(477.4	)%
Effective Income Tax Rate	808.3		%	27.8		%	780.5		%			705.7		%	63.4		%	642.3		%

Results of Operations

~~Six~~Nine Months Ended ~~June~~September 30, 2013 Compared with ~~Six~~Nine Months Ended ~~June~~September 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $1478 million, or $~~(0.06)~~(0.34) per diluted share, for the ~~six~~nine months ended ~~June~~September 30, 2013. Net income attributable to CONSOL Energy shareholders was $~~250~~239 million, or $~~1.09~~1.04 per diluted share, for the ~~six~~nine months ended ~~June~~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 $~~158~~245 million of earnings before income tax for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~419~~427 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The total coal division sold ~~29.0~~43.4 million tons of coal produced from CONSOL Energy mines for the ~~six~~nine months ended ~~June~~September 30, 2013 and ~~29.6~~41.7 million tons of coal produced from CONSOL Energy mines for the ~~six~~nine months ended ~~June~~September 30, 2012.

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


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	63.17	$	67.37	$	(4.20	)	(6.2	)%	$	62.54	$	67.35	$	(4.81	)	(7.1	)%
Average Cost of Goods Sold per ton	51.25		53.36		(2.11		)	(4.0	)%	50.99		54.09		(3.10		)	(5.7	)%
Margin per ton sold	$	11.92	$	14.01	$	(2.09	)	(14.9	)%	$	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 ~~5.0~~7.3 million tons on the export market at an average sales price of ~~$72.74~~$71.52 for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~6.7~~8.8 million tons at an average price of ~~$75.85~~$76.24 per ton for the ~~six~~nine months ended ~~June~~September 30, 2012. All other tons were sold on the domestic market.

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 iswas the result of the mine being idled March 12, 2013 until May ~~20th~~20, 2013 due to ~~the fire, as previously discussed. In~~a fire. Also, in March and April 2012, the Blacksville No. 2 Mine ran the continuous miners and worked on various projects, ~~but~~while the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.

~~Costs were improved due to a reduction in gas well plugging costs at the Shoemaker Mine and due to the shutdown of the~~The Fola Mining Complex was idled in August ~~2012.~~

~~Average~~2012 which resulted in lower direct operating costs ~~were impaired due to CONSOL Energy entering into several new leases for various types of mining equipment at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.~~

~~In March and April 2012,~~per ton produced in the ~~Buchanan Mine ran the continuous miners and worked on various projects, but the longwall~~period-to-period comparison. The mine, which was idled ~~resulting in lower 2012 unit costs. This did not occur in~~for market reasons, was a higher cost mining operation which when removed reduced the ~~2013 period.~~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 ~~timing~~2012 period as a result of ~~assets going~~the structural failure and due to the idling of the Buchanan Mine in ~~service or being fully depreciated.~~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 $57 million loss before income tax for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $1325 million of earnings before income tax for the ~~six~~nine months ended ~~June~~September 30, 2012. Total gas production was ~~77.8~~123.9 billion cubic feet for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~75.0~~114.5 billion cubic feet for the ~~six~~nine months ended ~~June~~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 Six Months Ended June 30,								For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change	2013		2012		Variance		Percent Change
Average Sales Price per thousand cubic feet sold	$	4.38	$	4.12	$	0.26		6.3%	$	4.31	$	4.14	$	0.17	4.1%
Average Costs per thousand cubic feet sold	3.65		3.36		0.29			8.6%	3.49		3.36		0.13		3.9%
Margin per thousand cubic feet sold	$	0.73	$	0.76	$	(0.03	)	(3.9)%	$	0.82	$	0.78	$	0.04	5.1%

Total gas division outside sales revenues were $~~341~~534 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~309~~475 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The increase was primarily due to the ~~3.7%~~8.2% increase in volumes sold, along with a ~~6.3%~~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 ~~36.3~~60.3 billion cubic feet of our produced gas sales volumes for the ~~six~~nine months ended ~~June~~September 30, 2013 at an average price of ~~$4.75~~$4.71 per thousand cubic feet. These financial hedges represented ~~38.2~~57.5 billion cubic feet of our produced gas sales volumes for the ~~six~~nine months ended ~~June~~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.

Lifting costs increased due to increased accretion expense on the well plugging liability as well as increased salt water disposal costs. ~~This impairment was~~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.

~~Higher units-of-production depreciation,~~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 Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Consulting and professional services	$	15	$	12	$	3		25.0	%
Employee Wages and Related Expenses										$	40	$	46	$	(6	)	(13.0	)%
Contributions	7		5		2			40.0	%	8		9		(1		)	(11.1	)%
Advertising and promotion	4		4		—			—	%
Employee wages and related expenses	27		32		(5		)	(15.6	)%
Advertising and Promotion										6		6		—			—	%
Consulting and Professional Services										23		17		6			35.3	%
Miscellaneous	14		13		1			7.7	%	20		21		(1		)	(4.8	)%
Total Company General and Administrative Expenses	$	67	$	66	$	1		1.5	%	$	97	$	99	$	(2	)	(2.0	)%

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

~~Contributions increased $2 million related to various transactions that occurred throughout both periods, none of which are individually material.~~

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

Employee wages and related expenses decreased $5$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 ~~increased slightly~~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 ~~$155~~$219 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$131~~$195 million for the ~~six~~nine months ended ~~June~~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 ~~$32 million related to~~expense. Pension settlement expenses were required when lump sum distributions made for the 2013 plan year ~~exceeding~~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 ~~Postretirement~~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.~~increase.

6465

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

The coal segment contributed $~~158~~245 million of earnings before income tax in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~419~~427 million in the ~~six~~nine months ended ~~June~~September 30, 2012. Variances by the individual coal segments are discussed below.


	For the Six Months Ended														Difference to Six Months Ended															For the Nine Months Ended														Difference to Nine Months Ended
	June 30, 2013														June 30, 2012															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			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	$	1,459		$	116	$	258		$	—		$	1,833		$	(101	)	$	(16	)	$	(35	)	$	(6	)	$	(158	)	$	2,212		$	145	$	356		$	—		$	2,713		$	(16	)	$	(35	)	$	(47	)	$	(6	)	$	(104	)
Purchased Coal	—			—		—			11			11			—			—			—			3			3			—			—		—			18			18			—			—			—			5			5
Total Outside Sales	1,459			116		258			11			1,844			(101		)	(16		)	(35		)	(3		)	(155		)	2,212			145		356			18			2,731			(16		)	(35		)	(47		)	(1		)	(99		)
Freight Revenue	—			—		—			24			24			—			—			—			(75		)	(75		)	—			—		—			36			36			—			—			—			(90		)	(90		)
Other Income	1			2		—			61			64			1			(4		)	—			(150		)	(153		)	2			2		—			85			89			1			(5		)	—			(144		)	(148		)
Total Revenue and Other Income	1,460			118		258			96			1,932			(100		)	(20		)	(35		)	(228		)	(383		)	2,214			147		356			139			2,856			(15		)	(40		)	(47		)	(235		)	(337		)
Costs and Expenses:
Beginning inventory costs	58			—		21			—			79			(32		)	—			5			—			(27		)	58			—		21			—			79			(31		)	(2		)	5			—			(28		)
Total direct operating costs	760			57		102			102			1,021			(49		)	(6		)	(13		)	39			(29		)	1,154			72		147			140			1,513			19			(12		)	(13		)	6			—
Total royalty/production taxes	102			3		14			1			120			(5		)	(4		)	(4		)	(1		)	(14		)	153			4		20			1			178			1			(5		)	(5		)	(1		)	(10		)
Total direct services to operations	117			10		12			124			263			(35		)	(3		)	1			(21		)	(58		)	183			13		18			170			384			(27		)	(6		)	1			(40		)	(72		)
Total retirement and disability	88			6		13			8			115			(4		)	—			(3		)	1			(6		)	133			7		20			11			171			—			(2		)	(3		)	(4		)	(9		)
Depreciation, depletion and amortization	145			11		20			27			203			(13		)	(3		)	(1		)	19			2			224			14		30			40			308			(1		)	(5		)	—			17			11
Ending inventory costs	(42		)	—		(9		)	—			(51		)	68			—			17			—			85			(51		)	—		(7		)	—			(58		)	16			—			26			1			43
Total Costs and Expenses	1,228			87		173			262			1,750			(70		)	(16		)	2			37			(47		)	1,854			110		249			362			2,575			(23		)	(32		)	11			(21		)	(65		)
Freight Expense	—			—		—			24			24			—			—			—			(75		)	(75		)	—			—		—			36			36			—			—			—			(90		)	(90		)
Total Costs	1,228			87		173			286			1,774			(70		)	(16		)	2			(38		)	(122		)	1,854			110		249			398			2,611			(23		)	(32		)	11			(111		)	(155		)
Earnings (Loss) Before Income Taxes	$	232		$	31	$	85		$	(190	)	$	158		$	(30	)	$	(4	)	$	(37	)	$	(190	)	$	(261	)	$	360		$	37	$	107		$	(259	)	$	245		$	8		$	(8	)	$	(58	)	$	(124	)	$	(182	)

6566

THERMAL COAL SEGMENT

The thermal coal segment contributed $~~232~~360 million to total Company earnings before income tax for the ~~six~~nine months ended ~~June~~September 30, 2013 and $~~262~~352 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	24.6		25.3		(0.7		)	(2.8	)%	37.4		36.0		1.4			3.9	%
Average Sales Price Per Thermal Ton Sold	$	59.19	$	61.66	$	(2.47	)	(4.0	)%	$	59.16	$	61.79	$	(2.63	)	(4.3	)%

Beginning Inventory Costs Per Thermal Ton	$	50.92	$	58.32	$	(7.40	)	(12.7	)%	$	50.92	$	58.32	$	(7.40	)	(12.7	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	31.30	$	31.45	$	(0.15	)	(0.5	)%	$	30.98	$	31.68	$	(0.70	)	(2.2	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	4.21		4.16		0.05			1.2	%	4.11		4.25		(0.14		)	(3.3	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.82		5.90		(1.08		)	(18.3	)%	4.90		5.89		(0.99		)	(16.8	)%
Total Retirement and Disability Per Thermal Ton Produced	3.63		3.58		0.05			1.4	%	3.56		3.71		(0.15		)	(4.0	)%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.96		6.12		(0.16		)	(2.6	)%	6.02		6.28		(0.26		)	(4.1	)%
Total Production Costs Per Thermal Ton Produced	$	49.92	$	51.21	$	(1.29	)	(2.5	)%	$	49.57	$	51.81	$	(2.24	)	(4.3	)%

Ending Inventory Costs Per Thermal Ton	$	55.36	$	56.03	$	(0.67	)	(1.2	)%	$	52.26	$	51.55	$	0.71		1.4	%

Total Costs Per Thermal Ton Sold	$	49.81	$	51.32	$	(1.51	)	(2.9	)%	$	49.57	$	52.06	$	(2.49	)	(4.8	)%
Average Margin Per Thermal Ton Sold	$	9.38	$	10.34	$	(0.96	)	(9.3	)%	$	9.59	$	9.73	$	(0.14	)	(1.4	)%

Thermal coal revenue was ~~$1,460~~$2,212 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$1,560~~$2,228 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The ~~$100~~$16 million decrease was attributable to a $~~2.47~~2.63 per ton lower average sales price ~~and~~offset, in part, by a ~~0.7~~1.4 million ~~reduction~~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. ~~Also, 1.5~~The decrease in price was partially offset by 2.4 million tons of thermal coal ~~were~~being priced on the export market at an average sales price of ~~$61.67~~$62.47 per ton for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~3.3~~4.1 million tons at an average price of ~~$57.12~~$58.10 per ton for the ~~six~~nine months ended ~~June~~September 30, 2012.

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 ~~$1,228~~$1,854 million for the ~~six~~nine months ended ~~June~~September 30, 2013, or ~~$70~~$23 million lower than the ~~$1,298~~$1,877 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Total cost of goods sold for thermal coal was ~~$49.81~~$49.57 per ton in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$51.32~~$52.06 per ton in the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease in total dollars and unit costs ~~of goods sold~~ per thermal ton was due to the items described below.

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. 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~~Mine was idled ~~on March 12,~~in 2013 ~~and resumed production on~~until May ~~20, 2013~~20th due to the fire that was previously ~~discussed, this~~discussed. This resulted in a reduction in all direct operating ~~costs.~~

~~In March and April 2012,~~costs in the ~~Blacksville No. 2 Mine ran~~current period, as well as a majority of the ~~continuous miners and worked on various projects, but the longwall was idled resulting in higher 2012~~ unit costs. ~~This did not occur in 2013.~~

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

Royalties and production taxes ~~decreased $5~~increased $1 million to ~~$102~~$153 million in the current period. ~~Average cost per thermal ton produced~~Total dollars increased ~~$0.05 per ton to $4.21 per ton sold,~~ due to ~~lower~~the increase in production volumes, ~~and~~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.

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.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, 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 $88 million for the ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to $92 million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012~~. The decrease in the thermal coal retirement and disability 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-retirement benefit plan that occurred ~~June 30, 2012. Average cost per thermal ton produced increased $0.05 per ton to $3.63 per ton sold due to lower production volumes.~~

~~Depreciation, depletion and amortization for the thermal coal segment was $145 million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to $158 million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. Unit costs per thermal ton produced were lower in the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012~~ ~~due to the idling of the Fola Mining Complex in August 2012.~~

~~Changes in thermal coal inventory volumes and carrying value resulted in $16 million of cost of goods sold in the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to a $20 million reduction of cost of goods sold in the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. Thermal coal inventory was 0.8 million tons at~~ ~~June 30, 2013~~ ~~compared to 2.0 million tons at~~ ~~June 30, 2012~~.

~~HIGH VOL METALLURGICAL COAL SEGMENT~~

~~The high volatile metallurgical coal segment contributed $~~31 ~~million to total Company earnings before income tax for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to $~~35 ~~million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:~~

For the Six Months Ended June 30,
2013 2012 Variance
Percent
Change
Company Produced High Vol Met Tons Sold (in millions) 1.8
2.2
(0.4 ) (18.2 )%
Average Sales Price Per High Vol Met Ton Sold $ 64.57
$ 60.95
$ 3.62
5.9 %

Beginning Inventory Costs Per High Vol Met Ton $ —
$ —
$ —
— %

Total Direct Operating Costs Per High Vol Met Ton Produced $ 31.87
$ 29.03
$ 2.84
9.8 %
Total Royalty/Production Taxes Per High Vol Met Ton Produced 1.44
3.17
(1.73 ) (54.6 )%
Total Direct Services to Operations Per High Vol Met Ton Produced 5.86
6.14
(0.28 ) (4.6 )%
Total Retirement and Disability Per High Vol Met Ton Produced 3.32
2.91
0.41
14.1 %
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced 5.93
6.26
(0.33 ) (5.3 )%
     Total Production Costs Per High Vol Met Ton Produced $ 48.42
$ 47.51
$ 0.91
1.9 %

Ending Inventory Costs Per High Vol Met Ton $ —
$ —
$ —
— %

     Total Costs Per High Vol Met Ton Sold $ 48.42
$ 47.51
$ 0.91
1.9 %
     Margin Per High Vol Met Ton Sold $ 16.15
$ 13.44
$ 2.71
20.2 %

~~High volatile metallurgical coal revenue was $118~~ ~~million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to $138~~ ~~million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012~~. Average sales prices for high volatile metallurgical coal increased $3.62 per ton in a period-to-period comparison. CONSOL Energy priced 1.6 million tons of high volatile metallurgical coal in the export market at an average sales price of $62.21 per ton for the ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to 1.9 million tons at an average price of $58.15 per ton for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. 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 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 $87 million for the ~~six months~~ ~~ended~~ ~~June 30, 2013, or $16 million lower than the $103 million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. Total cost of goods sold for high volatile metallurgical coal was $48.42 per ton in the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to $47.51 per ton in the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. The increase in cost of goods sold per high volatile metallurgical ton was due to the items described below.~~

~~Royalties and production taxes improved $4 million in the current period due primarily to the shutdown of the Fola Mining Complex in August 2012.~~

~~costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for high volatile metallurgical coal were $~~10 ~~million in the current period compared to~~ ~~$13~~ million in the prior period. Direct services to the operations for high volatile metallurgical coal were $5.86 per ton in the current period compared to $6.14 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:

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

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.

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.

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.

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 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 $6$7 million for the ~~six~~nine months ended ~~June~~September 30, 2013 ~~and~~ compared to $~~June~~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 ~~volumes had a negative impact on the unit costs.~~tons.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was ~~$11~~$14 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and ~~$14~~$19 million for the ~~six~~nine months ended ~~June~~September 30, 2012. ~~Unit~~Total dollars and unit costs per high volatile metallurgical ton produced were lower in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to the ~~six~~nine months ended ~~June~~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 ~~six~~nine months ended ~~June~~September 30, 2013 and ~~June~~September 30, 2012. There was no high volatile metallurgical coal inventory at ~~June~~September 30, 2013 or ~~June~~September 30, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $85107 million to total Company earnings before income tax in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~122~~165 million in the ~~six~~nine months ended ~~June~~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 Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	2.6		2.0		0.6			30.0	%	3.7		2.8		0.9			32.1	%
Average Sales Price Per Low Vol Met Ton Sold	$	100.41	$	146.40	$	(45.99	)	(31.4	)%	$	95.89	$	143.30	$	(47.41	)	(33.1	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	86.38	$	67.60	$	18.78		27.8	%	$	86.38	$	67.60	$	18.78		27.8	%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	40.96	$	53.38	$	(12.42	)	(23.3	)%	$	41.00	$	54.00	$	(13.00	)	(24.1	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.79		8.63		(2.84		)	(32.9	)%	5.60		8.66		(3.06		)	(35.3	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	4.85		5.35		(0.50		)	(9.3	)%	5.20		5.76		(0.56		)	(9.7	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.37		7.62		(2.25		)	(29.5	)%	5.42		7.90		(2.48		)	(31.4	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.10		9.65		(1.55		)	(16.1	)%	8.55		10.10		(1.55		)	(15.3	)%
Total Production Costs Per Low Vol Met Ton Produced	$	65.07	$	84.63	$	(19.56	)	(23.1	)%	$	65.77	$	86.42	$	(20.65	)	(23.9	)%

Ending Inventory Costs Per Low Vol Met Ton	$	64.76	$	69.84	$	(5.08	)	(7.3	)%	$	65.42	$	87.32	$	(21.90	)	(25.1	)%

Total Costs Per Low Vol Met Ton Sold	$	67.10	$	85.43	$	(18.33	)	(21.5	)%	$	67.12	$	84.75	$	(17.63	)	(20.8	)%
Margin Per Low Vol Met Ton Sold	$	33.31	$	60.97	$	(27.66	)	(45.4	)%	$	28.77	$	58.55	$	(29.78	)	(50.9	)%

Low volatile metallurgical coal revenue was $~~258~~356 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~293~~403 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $3547 million decrease was primarily attributable to a $~~45.99~~47.41 per ton lower average sales price. ~~Average~~The average sales ~~prices~~price for low volatile metallurgical coal decreased in the period-to-period comparison due to the

weakening in the global metallurgical coal ~~demand.~~market. For the 2013 period, ~~2.0~~2.8 million tons of low volatile metallurgical coal were priced on the export market at an average price of ~~$89.53~~$86.30 per ton compared to ~~1.6~~2.1 million tons at an average price of ~~$136.32~~$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 ~~$173~~$249 million for the ~~six~~nine months ended ~~June~~September 30, 2013, or $2$11 million higher than the ~~$171~~$238 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Total cost of goods sold for low volatile metallurgical coal was ~~$67.10~~$67.12 per ton in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$85.43~~$84.75 per ton in the ~~six~~nine months ended ~~June~~September 30, 2012. The increase in total dollars and decrease in ~~cost of goods sold~~unit costs per low volatile metallurgical ton was due to the ~~following~~ 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 ~~$102~~$147 million in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$115~~$160 million in the ~~six~~nine months ended ~~June~~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 ~~$40.96~~$41.00 per ton produced in the current period compared to ~~$53.38~~$54.00 per ton produced in the prior period. Low volatile metallurgical coal production was ~~2.5~~0.9 million tons higher in the ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared~~current period primarily due to ~~2.1 million tons~~Buchanan Mine being temporarily idled in the ~~six months~~ ~~ended~~ ~~June 30,~~ 2012. period, as mentioned above.

Royalties and production taxes improved $4$5 million to ~~$14~~$20 million in the current period compared to ~~$18~~$25 million in the prior period. Unit costs also improved ~~$2.84~~$3.06 per low volatile metallurgical ton produced to ~~$5.79~~$5.60 per ton produced in the

current period compared to ~~$8.63~~$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 ~~prices.~~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 ~~$12~~$18 million in the current period and ~~$11~~$17 million in the prior ~~periods.~~period. Direct services to operations for low volatile metallurgical coal were ~~$4.85~~$5.20 per ton produced in the current period compared to ~~$5.35~~$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 and due to higher tons~~Plan. This, coupled with the increase in volumes, resulted in an improvement in the unit costs of ~~coal produced~~$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-retirement~~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 $1320 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $1623 million for the ~~six~~nine months ended ~~June~~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-retirement~~post-employment benefit plan that occurred on ~~June~~September 30, 2012. This, coupled with the increase in volumes, resulted in an improvement onin the unit costs of ~~$2.25~~$2.48 in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was ~~$20~~$30 million for the ~~six~~nine months ended ~~June~~September 30, 2013 ~~compared to $21 million~~and for the ~~six~~nine months ended ~~June~~September 30, 2012. Unit costs per low volatile metallurgical ~~tons~~ton produced were $1.55 lower in the ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared~~current period due to the ~~six months~~0.9 ~~ended~~ ~~June 30, 2012~~ ~~primarily due to the Amonate Complex being idled~~million increase in ~~September 2012 and the Buchanan reverse osmosis plant being temporarily idled in April and May 2013.~~production tons.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of ~~$12~~$14 million to cost of goods sold in the ~~six~~nine months ended ~~June~~September 30, 2013 and a decrease of ~~$10~~$17 million to cost of goods sold in the ~~six~~nine months ended ~~June~~September 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at ~~June~~September 30, 2013 compared to ~~0.3~~0.4 million tons at ~~June~~September 30, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $~~190~~259 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and had ~~zero net~~a loss before income ~~before taxes~~tax of $135 million for the ~~six~~nine months ended ~~June~~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 ~~six~~nine months ended ~~June~~September 30, 2012. No coal was recovered during the reclamation process at idled facilities for the ~~six~~nine months ended ~~June~~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 ~~$11~~$18 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $8$13 million for the ~~six~~nine months ended ~~June~~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 ~~$24~~$36 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$99~~$126 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The ~~$75~~$90 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $6185 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~211~~229 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $~~150~~144 million decrease is due to the following items:

Gain on sale of assets attributable to the Other Coal segment was ~~$27~~$46 million in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~$180~~$181 million in the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease of ~~$153~~$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 ~~change~~$2 million decrease was related to various transactions that occurred throughout both periods, none of which were individually material.

Equity in earnings of affiliates ~~increased $5~~decreased $1 million due to ~~higher~~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 ~~six~~nine months ended ~~June~~September 30, 2013, $3$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.

In the six months ended June 30, 2012, there was an additional $6 million in income that was related to certain thermal coal contract buyouts. There were no such items in the six months ended June 30, 2013.

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

Other coal segment total costs were $~~286~~398 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~324~~509 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease of $38111 million was due to the following items:

For the Six Months Ended June 30,
2013 2012 Variance
Blacksville No. 2 Mine Fire $ 38
$ —
$ 38
Stock-based compensation 25
16
9
Purchased coal 21
18
3
Closed and idle mines 68
71
(3 )
Freight expense 24
99
(75 )
Other 110
120
(10 )
Total Other Coal Segment Costs $ 286
$ 324
$ (38 )



	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	)

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 recovery has not been reflected in the six months ended ~~June 30, 2013~~.

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 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 due to an increase in the amount of coal that was purchased to fulfill various contracts.~~

~~Closed and idle mine costs decreased approximately $3 million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2013~~ ~~compared to the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012~~. There was a $24 million decrease in asset retirement obligations. This was primarily due to 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 offset, in part, by an increase of $13 million due to the idling of the Fola Mining Complex in August 2012, and an increase of $5 million due to the idling of the Amonate Complex in September 2012. 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.

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.

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 ~~$10~~$15 million due to various transactions that occurred throughout both periods, none of which were individually material.

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

The gas segment had a loss of $57 million before income tax in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to earnings of $1325 million in the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended													Difference to Six Months Ended														For the Nine Months Ended													Difference to Nine Months Ended
	June 30, 2013													June 30, 2012														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			CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	172	$	66		$	95	$	6		$	339		$	(15	)	$	(3	)	$	47	$	2		$	31		$	255	$	99		$	167	$	11		$	532		$	(26	)	$	(2	)	$	83	$	4		$	59
Related Party	2		—			—		—			2			1			—			—		—			1			2		—			—		—			2			—			—			—		—			—
Total Outside Sales	174		66			95		6			341			(14		)	(3		)	47		2			32			257		99			167		11			534			(26		)	(2		)	83		4			59
Gas Royalty Interest	—		—			—		31			31			—			—			—		9			9			—		—			—		47			47			—			—			—		12			12
Purchased Gas			—			—		3			3			—			—			—		1			1					—			—		4			4			—			—			—		2			2
Other Income	—		—			—		24			24			—			—			—		(10		)	(10		)	—		—			—		37			37			—			—			—		(9		)	(9		)
Total Revenue and Other Income	174		66			95		64			399			(14		)	(3		)	47		2			32			257		99			167		99			622			(26		)	(2		)	83		9			64
Lifting	19		17			9		2			47			—			(4		)	3		1			—			27		26			14		4			71			(1		)	(5		)	5		3			2
Ad Valorem, Severance, and Other Taxes	4		6			3		(1		)	12			(1		)	1			1		(1		)	—			7		7			6		—			20			—			—			3		(2		)	1
Gathering	58		19			19		1			97			7			8			10		—			25			85		26			30		3			144			7			8			13		3			31
Gas Direct Administrative, Selling & Other	4		4			13		2			23			(5		)	(4		)	8		(1		)	(2		)	6		7			19		3			35			(6		)	(4		)	9		—			(1		)
Depreciation, Depletion and Amortization	45		30			26		4			105			2			—			8		(2		)	8			68		44			45		6			163			2			—			14		(1		)	15
General & Administration	—		—			—		22			22			—			—			—		3			3			—		—			—		33			33			—			—			—		4			4
Gas Royalty Interest	—		—			—		25			25			—			—			—		8			8			—		—			—		38			38			—			—			—		10			10
Purchased Gas	—		—			—		2			2			—			—			—		1			1			—		—			—		3			3			—			—			—		1			1
Exploration and Other Costs	—		—			—		21			21			—			—			—		—			—			—		—			—		44			44			—			—			—		15			15
Other Corporate Expenses	—		—			—		46			46			—			—			—		6			6			—		—			—		72			72			—			—			—		16			16
Interest Expense	—		—			—		4			4			—			—			—		1			1			—		—			—		6			6			—			—			—		2			2
Total Cost	130		76			70		128			404			3			1			30		16			50			193		110			114		212			629			2			(1		)	44		51			96
Earnings Before Income Tax	$	44	$	(10	)	$	25	$	(64	)	$	(5	)	$	(17	)	$	(4	)	$	17	$	(14	)	$	(18	)	$	64	$	(11	)	$	53	$	(113	)	$	(7	)	$	(28	)	$	(1	)	$	39	$	(42	)	$	(32	)

7374

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $4464 million to the total Company earnings before income tax for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $6192 million for the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	41.6		45.1		(3.5		)	(7.8	)%	62.6		66.8		(4.2		)	(6.3	)%
Average CBM sales price per thousand cubic feet sold	$	4.17	$	4.18	$	(0.01	)	(0.2	)%	$	4.11	$	4.24	$	(0.13	)	(3.1	)%
Average CBM lifting costs per thousand cubic feet sold	0.46		0.43		0.03			7.0	%	0.44		0.42		0.02			4.8	%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.09		0.12		(0.03		)	(25.0	)%	0.10		0.11		(0.01		)	(9.1	)%
Average CBM gathering costs per thousand cubic feet sold	1.39		1.12		0.27			24.1	%	1.36		1.17		0.19			16.2	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.09		0.21		(0.12		)	(57.1	)%	0.10		0.18		(0.08		)	(44.4	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.09		0.95		0.14			14.7	%	1.08		0.99		0.09			9.1	%
Total Average CBM costs per thousand cubic feet sold	3.12		2.83		0.29			10.2	%	3.08		2.87		0.21			7.3	%
Average Margin for CBM	$	1.05	$	1.35	$	(0.30	)	(22.2	)%	$	1.03	$	1.37	$	(0.34	)	(24.8	)%

CBM sales revenues were $~~174~~257 million in the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~188~~283 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $1426 million decrease was primarily due to ana ~~7.8%~~6.3% decrease in volumes sold and a ~~0.2%~~3.1% decrease in average sales price per thousand cubic feet sold. CBM sales volumes decreased ~~3.5~~4.2 billion cubic feet for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to the 2012 period primarily due to normal well declines ~~without a corresponding increase in~~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 ~~20.6~~34.4 billion cubic feet of our produced CBM gas sales volumes for the ~~six~~nine months ended ~~June~~September 30, 2013 at an average price of ~~$4.60~~$4.56 per thousand cubic feet. For the ~~six~~nine months ended ~~June~~September 30, 2012, these financial hedges represented ~~23.1~~34.5 billion cubic feet at an average price of ~~$5.33~~$5.34 per thousand cubic feet.

Total costs for the CBM segment were $~~130~~193 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~127~~191 million for the ~~six~~nine months ended ~~June~~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 $1927 million for the ~~six~~nine months ended ~~June~~September 30, 2013 ~~and 2012. The~~compared to $~~0.03~~28 ~~per thousand cubic feet increase~~million for the nine months ended September 30, 2012. The decrease in ~~average lifting~~total dollars and unit costs ~~during~~was primarily due to lower road maintenance and lower contractor services in the ~~current year is directly related to~~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 ~~were~~remained consistent at $47 million for the ~~six~~nine months ended ~~June~~September 30, 2013 ~~compared to $~~5 ~~million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012. The~~ $1 ~~million decrease in total dollars was primarily due to a reassessment of our 2012 ad valorem taxes paid to Tazewell County, Virginia resulting in a current period refund. Decreased ad valorem~~ and ~~severance expense resulted in a decrease in average unit costs, offset, in part, by an increase due to the reduction of volumes.~~2012.

•CBM gathering costs were $5885 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $5178 million for the ~~six~~nine months ended ~~June~~September 30, 2012. This$7 ~~million~~ increase in total dollars and ~~the $0.27~~average per ~~thousand cubic feet increase in average CBM gathering~~ unit costs ~~are related~~was due to increased transportation costs, increased power ~~costs due to higher utility rates,~~fees, and increased pipeline ~~maintenance expense, increased~~and road ~~maintenance expenses and lower volumes sold~~maintenance. Unit costs were also negatively impacted by the decrease in ~~the period-to-period comparison.~~gas sales volumes.

•CBM direct administrative, selling and other costs ~~for the CBM segment~~ were $46 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $912 million for the ~~six~~nine months ended ~~June~~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 ~~reduction~~decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $4568 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $4366 million for the ~~six~~nine months ended ~~June~~September 30, 2012. There was approximately ~~$31~~$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 ~~six~~nine months ended ~~June~~September 30, 2013. The production portion of depreciation, depletion and amortization was ~~$30~~$45 million, or ~~$0.66~~$0.68 per unit-of-production in the ~~six~~nine months ended ~~June~~September 30, 2012. There was approximately ~~$14~~$21 million, or ~~$0.34~~$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 ~~six~~nine months ended ~~June~~September 30, 2013. The non-production related depreciation, depletion and amortization was ~~$13~~$21 million, or ~~$0.29~~$0.31 per thousand cubic feet for the ~~six~~nine months ended ~~June~~September 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $1011 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to a loss before income tax of $610 million for the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended June 30,											For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	13.8			14.8			(1.0		)	(6.8	)%	20.6			21.8			(1.2		)	(5.5	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	4.78		$	4.63		$	0.15		3.2	%	$	4.81		$	4.62		$	0.19		4.1	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.22			1.39			(0.17		)	(12.2	)%	1.27			1.40			(0.13		)	(9.3	)%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.40			0.32			0.08			25.0	%	0.36			0.34			0.02			5.9	%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.39			0.78			0.61			78.2	%	1.26			0.81			0.45			55.6	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.33			0.56			(0.23		)	(41.1	)%	0.34			0.49			(0.15		)	(30.6	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.14			1.99			0.15			7.5	%	2.16			2.02			0.14			6.9	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.48			5.04			0.44			8.7	%	5.39			5.06			0.33			6.5	%
Average Margin for Shallow Oil and Gas	$	(0.70	)	$	(0.41	)	$	(0.29	)	70.7	%	$	(0.58	)	$	(0.44	)	$	(0.14	)	31.8	%

Shallow Oil and Gas sales revenues were $6699 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $69101 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $32 million decrease was primarily due to the ~~6.8%~~5.5% decrease in volumes sold, offset, in part, by a ~~3.2%~~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 ~~6.8~~10.6 billion cubic feet of our produced shallow oil and gas sales volumes for the ~~six~~nine months ended ~~June~~September 30, 2013 at an average price of ~~$5.24~~$5.21 per thousand cubic feet. For the ~~six~~nine months ended ~~June~~September 30, 2012, these financial hedges represented ~~9.5~~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 $76110 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $75111 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease in total dollars and increase in ~~total~~unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $1726 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $2131 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $45 million decrease toin total costs and $~~0.17~~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 $67 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and $5 ~~million for the~~ ~~six months~~ ~~ended~~ ~~June 30, 2012~~.2012. The $1 ~~million increase to total costs is primarily due to higher average sales prices in the current period. The~~ ~~$0.08~~0.02 per thousand cubic feet increase to average unit costs iswas primarily due to ~~higher average sales prices and~~ lower ~~sales volumes.~~gas volumes sold in the period-to-period comparison.

7576

•Shallow Oil and Gas gathering costs were $1926 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $1118 million for the ~~six~~nine months ended ~~June~~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 $47 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $811 million for the ~~six~~nine months ended ~~June~~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 $3044 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and 2012. There was approximately ~~$26~~$39 million, or ~~$1.87~~$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 ~~six~~nine months ended ~~June~~September 30, 2013. There was approximately ~~$26~~$38 million, or ~~$1.74~~$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 ~~six~~nine months ended ~~June~~September 30, 2012. There was approximately $4$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 ~~six~~nine months ended ~~June~~September 30, 2013. There was $4$6 million, or ~~$0.25~~$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 ~~six~~nine months ended ~~June~~September 30, 2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $2553 million to the total Company earnings before income tax for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $814 million for the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	21.0		13.9		7.1			51.1	%	38.5		24.0		14.5			60.4	%
Average Marcellus sales price per thousand cubic feet sold	$	4.51	$	3.41	$	1.10		32.3	%	$	4.35	$	3.48	$	0.87		25.0	%
Average Marcellus lifting costs per thousand cubic feet sold	0.45		0.43		0.02			4.7	%	0.38		0.38		—			—	%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.14		0.14		—			—	%	0.15		0.13		0.02			15.4	%
Average Marcellus gathering costs per thousand cubic feet sold	0.89		0.61		0.28			45.9	%	0.79		0.64		0.15			23.4	%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.60		0.34		0.26			76.5	%	0.48		0.43		0.05			11.6	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.22		1.31		(0.09		)	(6.9	)%	1.16		1.30		(0.14		)	(10.8	)%
Total Average Marcellus costs per thousand cubic feet sold	3.30		2.83		0.47			16.6	%	2.96		2.88		0.08			2.8	%
Average Margin for Marcellus	$	1.21	$	0.58	$	0.63		108.6	%	$	1.39	$	0.60	$	0.79		131.7	%

The Marcellus segment sales revenues were $95167 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $4884 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $4783 million increase is primarily due to a ~~51.1%~~60.4% increase in volumes sold, and a ~~32.3%~~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 ~~the improvement in general~~higher market prices and sales of natural gas liquids, offset by various gas swap transactions that matured in the ~~six~~nine months ended ~~June~~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 ~~8.8~~15.2 billion cubic feet of our produced Marcellus gas sales volumes for the ~~six~~nine months ended ~~June~~September 30, 2013 at an average price of ~~$4.74~~$4.69 per thousand cubic feet. For the ~~six~~nine months ended ~~June~~September 30, 2012, these financial hedges represented ~~5.5~~8.5 billion cubic feet at an average price of $4.97 per thousand cubic feet.

Total costs for the Marcellus segment were $70114 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $4070 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The increase in total dollars and unit costs for the Marcellus segment are due to the following items:

7677

•Marcellus lifting costs were $914 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $69 million for the ~~six~~nine months ended ~~June~~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 $36 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $23 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The increase ~~relates~~in total dollars and unit costs is primarily due to ~~the higher average sales price and~~ an increase in severance tax expense caused by higher average gas sales prices and the 60.4% increase in sales volumes ~~sold, as~~during the ~~per-unit costs remained consistent for the 2013 and 2012 periods.~~current period.

•Marcellus gathering costs were $1930 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $917 million for the ~~six~~nine months ended ~~June~~September 30, 2012. ~~Average gathering costs~~Total dollars increased~~$0.28~~ ~~per unit primarily~~ due to ~~increased~~higher firm transportation costs, ~~and~~ increased processing fees associated with natural gas ~~liquids.~~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 $1319 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $510 million for the ~~six~~nine months ended ~~June~~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 ~~volumes sold.~~sales volumes.

•Depreciation, depletion and amortization costs were $2645 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $1831 million for the ~~six~~nine months ended ~~June~~September 30, 2012. There was approximately ~~$25~~$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 infor the ~~six~~nine months ended ~~June 30, 2013~~. There was approximately $16 million, or $1.17 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the ~~six months~~ ~~ended~~ ~~June~~September 30, 2012. There was approximately $1 million, or ~~$0.02~~$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 ~~six~~nine months ended ~~June~~September 30, 2013. There was $2$3 million, or ~~$0.14~~$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 ~~six~~nine months ended ~~June~~September 30, 2012.

OTHER GAS SEGMENT

The other gas segment includes activity not assigned to the CBM, Shallow Oil and Gas or Marcellus ~~gas~~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 $611 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and $47 million for the ~~six~~nine months ended ~~June 31,~~ September 30, 2012. Total costs related to these other sales were $816 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and $1113 million for the ~~six~~nine months ended ~~June~~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 $3147 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $2235 million for the ~~six~~nine months ended ~~June~~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 Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	7.4		8.3		(0.9		)	(10.8	)%	10.9		13.2		(2.3		)	(17.4	)%
Average Sales Price Per thousand cubic feet	$	4.21	$	2.61	$	1.60		61.3	%	$	4.27	$	2.63	$	1.64		62.4	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $34 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and $2 million for the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended June 30,								For the Nine Months Ended September 30,
	2013		2012		Variance		Percent Change		2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.7		0.6		0.1		16.7	%	1.1		0.8		0.3		37.5	%
Average Sales Price Per thousand cubic feet	$	3.69	$	2.70	$	0.99	36.7	%	$	4.12	$	2.90	$	1.22	42.1	%

Other income was $2437 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $3446 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $109 million change was primarily due to a ~~$7 million~~ decrease in interest income ~~related~~of $12 million relating to the timing of scheduled collections on ~~the~~ notes receivable from the Noble joint venture transaction, offset by a $2$3 million ~~decrease in gains on dispositions of non-core acreage and equipment, and a $1 million decrease in various other transactions, none of which are individually material.~~increase related to increased earnings from our equity affiliates.

General and ~~administrative~~Administrative costs are allocated to the total gas segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $2233 million for the ~~six~~nine months ended ~~June~~September 30, 2013 and $1929 million for the ~~six~~nine months ended ~~June~~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 $2538 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $1728 million for the ~~six~~nine months ended ~~June~~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 Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	7.4		8.3		(0.9		)	(10.8	)%	10.9		13.2		(2.3		)	(17.4	)%
Average Cost Per thousand cubic feet sold	$	3.42	$	2.08	$	1.34		64.4	%	$	3.50	$	2.12	$	1.38		65.1	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that ~~we sell.~~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 ~~six~~nine months ended ~~June 30, 2013~~ ~~and~~ $1 ~~million for the~~ ~~six months~~ ~~ended~~ ~~June~~September 30, 2012.


	For the Six Months Ended June 30,								For the Nine Months Ended September 30,
	2013		2012		Variance		Percent Change		2013		2012		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.6		0.1		16.7	%	1.1		1.0		0.1		10.0	%
Average Cost Per thousand cubic feet sold	$	2.70	$	1.94	$	0.76	39.2	%	$	2.79	$	2.22	$	0.57	25.7	%

Exploration and other costs ~~remained consistent at~~were $2144 million for the ~~six~~nine months ended ~~June~~September 30, 2013 ~~and~~compared to $29 million for the nine months ended September 30, 2012.


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Marcellus Title Defects	$	9	$	—	$	9		100	%	$	22	$	2	$	20		1,000.0	%
Lease Expiration Costs										6		13		(7		)	(53.8	)%
Exploration	9		9		—			—	%	16		14		2			14.3	%
Lease Expiration Costs	3		12		(9		)	(75	)%
Total Exploration and Other Costs	$	21	$	21	$	—		—	%	$	44	$	29	$	15		51.7	%

million for the nine months ~~million.~~ended

~~Exploration expense remained consistent in~~September 30, 2013 compared to $2 million for the ~~period-to-period comparison.~~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 $97 million decrease is due to CONSOL Energy allowing ~~less~~fewer leases to expire in the current period when compared with the prior period.

78Exploration expense increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $4672 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $4056 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The $616 million increase in the period-to-period comparison was made up of the following items:


	For the Six Months Ended June 30,									For the Nine Months Ended September 30,
	2013		2012		Variance			Percent Change		2013		2012		Variance			Percent Change
Unutilized firm transportation	$	16	$	5	$	11		220	%	$	25	$	9	$	16		177.8	%
Stock-based compensation	14		10		4			40	%	19		15		4			26.7	%
Short-term incentive compensation										16		19		(3		)	(15.8	)%
Bank fees										5		5		—			—	%
Legal fees	2		2		—			—	%	2		3		(1		)	(33.3	)%
Bank fees	3		4		(1		)	(25	)%
PA Impact fees	—		4		(4		)	(100	)%	—		4		(4		)	(100.0	)%
Short-term incentive compensation	9		14		(5		)	(35.7	)%
Other	2		1		1			100	%	5		1		4			400.0	%
Total Other Corporate Expenses	$	46	$	40	$	6		15	%	$	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.~~increase, as well as additional processing capacity for natural gas liquids. . The $1116 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.

~~Legal fees~~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.

~~Bank Fees~~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. ~~On-going~~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.

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 projected lower payouts.

Other corporate related expense increased $14 million due to various transactions that occurred throughout both periods, none of which were individually material.

Interest expense related to the gas segment was $46 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $34 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Interest was incurred by the gas segment on the CNX Gas revolving credit facility and a capital lease. The $12 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 ~~six~~nine months ended ~~June~~September 30, 2013 compared to the ~~six~~nine months ended ~~June~~September 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 $~~153~~227 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to a loss before income tax of $~~102~~153 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The other segment also includes total Company income tax expense of $1590 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $8060 million for the ~~six~~nine months ended ~~June~~September 30, 2012.


	For the Six Months Ended June 30,											For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Sales—Outside	$	169		$	193		$	(24	)	(12.4	)%	$	248		$	281		$	(33	)	(11.7	)%
Other Income	8			7			1			14.3	%	13			9			4			44.4	%
Total Revenue	177			200			(23		)	(11.5	)%	261			290			(29		)	(10.0	)%
Cost of Goods Sold and Other Charges	207			172			35			20.3	%	303			250			53			21.2	%
Depreciation, Depletion & Amortization	13			12			1			8.3	%	19			18			1			5.6	%
Taxes Other Than Income Tax	6			6			—			—	%	8			9			(1		)	(11.1	)%
Interest Expense	104			112			(8		)	(7.1	)%	158			166			(8		)	(4.8	)%
Total Costs	330			302			28			9.3	%	488			443			45			10.2	%
Loss Before Income Tax	(153		)	(102		)	(51		)	50.0	%	(227		)	(153		)	(74		)	48.4	%
Income Tax	15			80			(65		)	(81.3	)%	90			60			30			50.0	%
Net Loss	$	(168	)	$	(182	)	$	14		(7.7	)%	$	(317	)	$	(213	)	$	(104	)	48.8	%

Industrial supplies:

Outside sales from industrial supplies ~~was~~were $~~108~~162 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~134~~192 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease of ~~$26~~$30 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $~~106~~159 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~130~~186 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The decrease of ~~$24~~$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 ~~was~~were $6186 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $5989 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The ~~increase~~decrease of $2$3 million was primarily attributable to higher per ton thru-put rates ~~at the CNX Marine Terminal~~ offset, in part, by decreased ~~thru-put.~~thru-put volumes.

Total costs related to the transportation operations were $5073 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $4265 million for the ~~six~~nine months ended ~~June~~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.

~~Miscellaneous other:~~

~~Additional other income of~~ $8 ~~million was recognized for the six months ended~~ ~~June 30, 2013~~ ~~compared to~~ $7 ~~million for the six months ended~~ ~~June 30, 2012. The~~ $1 ~~million increase was primarily due to an increase in interest income.~~

Other corporate costs in the other segment were $~~174~~256 million for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to $~~130~~192 million for the ~~six~~nine months ended ~~June~~September 30, 2012. Other corporate costs increased due to the following items:


	For the Six Months Ended June 30,							For the Nine Months Ended September 30,
	2013		2012		Variance			2013		2012		Variance
Pension Settlement	$	32	$	—	$	32		$	38	$	—	$	38
CNX Gas shareholder settlement	20		—		20
CNX Gas Shareholder Settlement								19		—		19
Corporate Initiative fees and Other Legal Charges								15		4		11
Bank fees	7		7		—			11		10		1
Interest Expense	104		113		(9		)	158		166		(8		)
Other	11		10		1			15		12		3
	$	174	$	130	$	44		$	256	$	192	$	64

Pension settlement ~~adjustment is~~expenses were required when the ~~result of accounting rules requiring acceleration of unrecognized actuarial losses when~~ lump sum ~~payments from a~~distributions made for the 2013 plan ~~exceed~~year exceeded the ~~annual projected~~total of the service and interest costs offor the ~~plan.~~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 ~~$20.2~~$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 ~~remained consistent~~increased $1 million primarily due to various transactions that occurred throughout both ~~periods.~~periods, none of which were individually material.

Interest expense decreased $9$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 $1$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 ~~2,969.4%~~809.9% for the ~~six~~nine months ended ~~June~~September 30, 2013 compared to ~~24.3%~~20.2% for the ~~six~~nine months ended ~~June~~September 30, 2012. The effective rates for the ~~six~~nine months ended ~~June~~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 ~~relationship between~~$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, ~~and~~excluding gain on sales of assets, approaches breakeven without corresponding reductions in excess percentage depletion, ~~impacts the~~ effective tax ~~rate.~~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 Six Months Ended June 30,											For the Nine Months Ended September 30,
	2013			2012			Variance			Percent Change		2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	1		$	330		$	(329	)	(99.6	)%	$	11		$	299		$	(288	)	(96.4	)%
Income Tax Expense	$	15		$	80		$	(65	)	(80.9	)%	$	90		$	60		$	30		49.6	%
Effective Income Tax Rate	2,969.4		%	24.3		%	2,945.1		%			809.9		%	20.2		%	789.7		%

8182

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 ~~3.44~~3.96 to 1.00 at ~~June~~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 ~~3.65~~3.21 to 1.00 at ~~June~~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 ~~0.12~~0.11 to 1.00 at ~~June~~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 ~~June~~September 30, 2013, the facility had no outstanding borrowings and $~~100~~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 ~~June~~September 30, 2013, eligible accounts receivable totaled approximately $~~181~~200 million. At ~~June~~September 30, 2013, the facility had ~~$41~~$44 million of outstanding borrowings and $~~159~~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 ~~36.85~~28.55 to 1.00 at ~~June~~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 ~~1.20~~0.75 to 1.00 at ~~June~~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 million~~$600,000 of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. At ~~June~~September 30, 2013, the facility had ~~$173~~$47 million drawn and $70 million of letters of credit outstanding, leaving $~~757~~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 $~~116~~102 million at ~~June~~September 30, 2013. The ineffective portion of these contracts was a gain of $2.6 million and a loss of ~~$3.8 million and $2.7 million~~$120 thousand during the three and ~~six~~nine months ended ~~June~~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 Six Months Ended June 30,								For the Nine Months Ended September 30,
	2013			2012			Change		2013			2012			Change
Cash flows from operating activities	$	393		$	368		$	25	$	589		$	530		$	59
Cash used in investing activities	$	(465	)	$	(484	)	$	19	$	(560	)	$	(587	)	$	27
Cash used in financing activities	$	122		$	(59	)	$	181	$	(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 ~~$265~~$317 million in 2013 due to lower net income in the period-to-period comparison.

Operating cash flows increased ~~$157~~$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 ~~$94~~$187 million. The decrease was comprised of ~~$54~~$69 million related to the completion of the Northern West Virginia RO system as well as a ~~$55~~$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 $5$6 million in 2013. ~~The decrease is offset, in part, by an increase of $20 million in longwall shield projects;~~


◦	Gas segment capital expenditures increased ~~$154~~$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 ~~$16~~$30 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Proceeds from the sale of assets ~~decreased $11~~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


◦	$4330 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 $5$1 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

~~The~~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. The remaining~~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 ~~$173~~$47 million of short term borrowings under the revolving credit facilities.

In 2013, CONSOL Energy repaid ~~$30~~$32 million of borrowings related to a miscellaneous ~~short term note payable and only $5~~borrowings. In 2012, CONSOL Energy repaid $7 million ~~in the 2012 period.~~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 ~~$29~~$28 million, respectively. This is compared to $85 million in dividends paid in the ~~second quarter of 2013. As compared to $57 million in dividends paid in the six~~nine months ended ~~June~~September 30, 2012.

In 2013, CONSOL Energy received $3$7 million of borrowing under its Securitization Facility.

~~$2 million in additional cash received~~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 ~~June~~September 30, 2013 (in thousands):


	Payments due by Year										Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	173,000	$	—	$	—	$	—	$	173,000	$	47,000	$	—	$	—	$	—	$	47,000
Borrowings Under Securitization Facility	40,719		—		—		—		40,719		44,364		—		—		—		44,364
Purchase Order Firm Commitments	174,317		6,297		—		—		180,614		308,396		98,652		60,686		30,240		497,974
Gas Firm Transportation	84,063		157,943		131,751		405,934		779,691		85,313		154,373		128,452		389,000		757,138
Long-Term Debt	4,585		8,488		1,505,220		1,610,292		3,128,585		4,606		8,537		1,504,927		1,610,291		3,128,361
Interest on Long-Term Debt	245,428		491,294		371,007		307,353		1,415,082		245,406		491,245		370,956		296,427		1,404,034
Capital (Finance) Lease Obligations	8,837		13,967		11,777		22,006		56,587		8,576		15,280		12,464		20,424		56,744
Interest on Capital (Finance) Lease Obligations	3,702		5,731		4,101		2,831		16,365		3,647		5,666		3,942		2,440		15,695
Operating Lease Obligations	131,738		242,520		171,199		155,385		700,842		134,204		244,544		171,852		155,729		706,329
Long-Term Liabilities—Employee Related (a)	223,458		441,956		435,786		2,307,981		3,409,181		222,405		442,026		433,053		2,307,138		3,404,622
Other Long-Term Liabilities (b)	242,092		184,738		82,254		482,786		991,870		369,276		176,349		75,131		515,256		1,136,012
Total Contractual Obligations (c)	$	1,331,939	$	1,552,934	$	2,713,095	$	5,294,568	$	10,892,536	$	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

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 ~~June~~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 $1.50 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

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

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

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

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

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

An aggregate principal amount of $57 million of capital leases with a weighted average interest rate of ~~6.35%~~6.24% per annum.

At ~~June~~September 30, 2013, CONSOL Energy also had no outstanding borrowings and had approximately $~~100~~104 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At ~~June~~September 30, 2013, CONSOL Energy had $4144 million in outstanding borrowings and had $~~159~~156 million of letters of credit outstanding under the accounts receivable securitization facility.

At ~~June~~September 30, 2013, CNX Gas, a wholly owned subsidiary of CONSOL Energy, had $~~173~~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 ~~June~~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 ~~June~~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

Amount Per Share

Record Date

Payment Date

July 26, 2013

0.125

August 9, 2013

August 23, 2013

0.125

August 9, 2013

August 23, 2013

April 26, 2013

0.125

May 10, 2013

May 24, 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

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 ~~3.65~~3.21 to 1.00 and our availability was approximately $1.4 billion at ~~June~~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 ~~six~~nine months ended ~~June~~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.~~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 ~~June~~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 ~~June~~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)~~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-Q~~10-

Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

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

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

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 ~~June~~September 30, 2013. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by ~~$45.2~~$52.5 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by ~~$45.1~~$52.0 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At ~~June~~September 30, 2013, CONSOL Energy had ~~$3,185 million~~$3.185 billion aggregate principal amount of debt outstanding under fixed-rate instruments and ~~$214~~$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 ~~June~~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 ~~$173~~$47 million at ~~June~~September 30, 2013 and bore interest at a weighted average rate of 1.76% per annum during the ~~six~~nine months ended ~~June~~September 30, 2013. Due to the level of borrowings against this facility and the low weighted average interest rate in the ~~six~~nine months ended ~~June~~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 ~~July 9,~~October 8, 2013, our hedged volumes for the periods indicated are as follows:


	For the Three Months Ended										For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year		March 31,		June 30,		September 30,		December 31,		Total Year
2013 Fixed Price Volumes
Hedged Mcf	N/A		N/A		24,046,537		24,046,537		48,093,074		N/A		N/A		N/A		23,985,249		23,985,249
Weighted Average Hedge Price per thousand cubic feet	N/A		N/A		$	4.62	$	4.62	$	4.62	N/A		N/A		N/A		$	4.64	$	4.64
2014 Fixed Price Volumes
Hedged Mcf	16,634,945		16,819,778		17,004,611		17,004,611		67,463,945		18,381,383		18,585,621		18,789,858		18,789,858		74,546,720
Weighted Average Hedge Price per thousand cubic feet	$	4.92	$	4.92	$	4.92	$	4.92	$	4.92	$	4.81	$	4.81	$	4.81	$	4.81	$	4.81
2015 Fixed Price Volumes
Hedged Mcf	13,194,340		13,340,943		13,487,547		13,487,547		53,510,377		15,846,729		16,022,804		16,198,879		16,198,879		64,267,291
Weighted Average Hedge Price per thousand cubic feet	$	4.24	$	4.24	$	4.24	$	4.24	$	4.24	$	4.18	$	4.18	$	4.18	$	4.18	$	4.18
2016 Fixed Price Volumes
Hedged Mcf	7,125,472		7,125,472		7,203,774		7,203,774		28,658,492		13,352,336		13,352,336		13,499,065		13,499,065		53,702,802
Weighted Average Hedge Price per thousand cubic feet	$	4.45	$	4.45	$	4.45	$	4.45	$	4.45	$	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 ~~June~~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 ~~nineteenth~~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



~~10.1~~4.1			~~Stipulation and Agreement~~Supplemental Indenture No. 4, dated as of ~~Compromise and Settlement,~~September 10, 2013, to Indenture dated ~~May 8, 2013, between~~as of April 1, 2010, by and among ~~(i) plaintiffs Harold L. Hurwitz and James R. Gummel, on their own behalf and on behalf~~CONSOL Energy Inc., certain subsidiaries of ~~the Class (as defined therein) and (ii) defendants CNX Gas Corporation,~~ CONSOL Energy Inc. and ~~certain individual defendants.~~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.

~~10.2~~4.2			~~Amendment~~Supplemental Indenture No. 1,4, dated ~~April 19,~~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 ~~Asset Acquisition~~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 ~~August 17, 2011, between~~September 23, 2013, by and among CNX ~~Gas Company~~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 ~~Noble Energy, Inc.~~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 ~~June~~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: ~~August 5,~~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)

9294