CNX Resources Corp - FORM 10-Q

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EX-95 - MINE SAFETY AND HEALTH ADMINISTRATION SAFETY DATA - CNX Resources Corp	exhibit95msha93015.htm
EX-10.2 - AMENDED AND RESTATED CHANGE IN CONTROL - CNX Resources Corp	cnx93015-ex102.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - CNX Resources Corp	cnx93015-ex321.htm
EX-10.3 - AMENDED AND RESTATED CHANGE IN CONTROL - CNX Resources Corp	cnx93015-ex103.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 - CNX Resources Corp	cnx-93015xex311.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 - CNX Resources Corp	cnx-93015xex312.htm
EX-10.1 - AMENDED AND RESTATED CHANGE IN CONTROL - CNX Resources Corp	cnx-93015xex101.htm
XML - IDEA: XBRL DOCUMENT - CNX Resources Corp	R9999.htm
EX-32.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - CNX Resources Corp	cnx93015-ex322.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended September 30, 2015



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of October 16, 2015
Common stock, $0.01 par value		229,053,634

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014.	3
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014	4
	Consolidated Balance Sheets at September 30, 2015 and December 31, 2014	5
	Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2015	7
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014	8
	Notes to Unaudited Consolidated Financial Statements	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	45

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	94

ITEM 4.	Controls and Procedures	95

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	95

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	95

ITEM 4.	Mine Safety Disclosures	96

ITEM 6.	Exhibits	97

GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS

The following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-Q:

Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf - One billion cubic feet of natural gas.

Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

Btu - One British thermal unit.

Mbbls - One thousand barrels of oil or other liquid hydrocarbons.

Mcf - One thousand cubic feet of natural gas.

Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

MMbtu - One million British Thermal units.

MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

NGL - Natural gas liquids.

Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.

PART I : FINANCIAL INFORMATION


ITEM 1.	CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



(Dollars in thousands, except per share data)	Three Months Ended					Nine Months Ended
(Unaudited)	September 30,					September 30,
Revenues and Other Income:	2015		2014			2015			2014
Natural Gas, NGLs and Oil Sales	$	202,007	$	257,358		$	658,498		$	753,399
Unrealized Gain on Commodity Derivative Instruments	99,137		—			134,205			—
Coal Sales	403,602		483,960			1,314,748			1,554,939
Other Outside Sales	5,129		73,673			24,596			213,047
Production Royalty Interests and Purchased Gas Sales	14,080		18,815			39,423			68,773
Freight-Outside Coal	3,219		2,497			13,995			22,551
Miscellaneous Other Income	38,640		40,784			112,400			165,815
Gain on Sale of Assets	48,124		7,529			54,604			12,615
Total Revenue and Other Income	813,938		884,616			2,352,469			2,791,139
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	26,454		30,005			83,385			85,622
Transportation, Gathering and Compression	92,606		68,234			258,329			179,813
Production, Ad Valorem, and Other Fees	8,475		8,486			24,605			28,817
Direct Administrative and Selling	10,711		14,060			38,630			39,216
Depreciation, Depletion and Amortization	89,742		82,538			262,356			225,766
Exploration and Production Related Other Costs	3,332		8,045			7,694			15,765
Production Royalty Interests and Purchased Gas Costs	10,989		15,751			30,751			58,518
Other Corporate Expenses	26,986		13,700			66,633			60,876
Impairment of Exploration and Production Properties	—		—			828,905			—
General and Administrative	12,513		14,874			42,086			47,755
Total Exploration and Production Costs	281,808		255,693			1,643,374			742,148
Coal Costs
Operating and Other Costs	173,178		344,992			756,045			1,033,088
Royalties and Production Taxes	19,101		23,306			63,474			77,397
Direct Administrative and Selling	8,225		10,682			26,192			34,354
Depreciation, Depletion and Amortization	63,242		65,640			195,707			188,405
Freight Expense	3,219		2,497			13,995			22,551
General and Administrative Costs	7,477		10,639			21,786			34,005
Other Corporate Expenses	10,680		10,113			32,863			41,444
Total Coal Costs	285,122		467,869			1,110,062			1,431,244
Other Costs
Miscellaneous Operating Expense	14,832		86,993			39,268			246,355
General and Administrative Costs	—		220			—			651
Depreciation, Depletion and Amortization	5		487			17			1,509
Loss on Debt Extinguishment	—		20,990			67,751			95,267
Interest Expense	48,558		55,397			150,187			170,539
Total Other Costs	63,395		164,087			257,223			514,321
Total Costs And Expenses	630,325		887,649			3,010,659			2,687,713
Earnings (Loss) Before Income Tax	183,613		(3,033		)	(658,190		)	103,426
Income Taxes	58,143		(1,388		)	(259,389		)	8,315
Income (Loss) From Continuing Operations	125,470		(1,645		)	(398,801		)	95,111
Loss From Discontinued Operations, net	—		—			—			(5,687		)
Net Income (Loss)	125,470		(1,645		)	(398,801		)	89,424
Less: Net Income Attributable to Noncontrolling Interest	6,490		—			6,490			—
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	118,980	$	(1,645	)	$	(405,291	)	$	89,424

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(CONTINUED)



	Three Months Ended					Nine Months Ended
(Dollars in thousands, except per share data)	September 30,					September 30,
(Unaudited)	2015		2014			2015			2014
Earnings Per Share
Basic
Income (Loss) from Continuing Operations	$	0.52	$	(0.01	)	$	(1.77	)	$	0.41
Loss from Discontinued Operations	—		—			—			(0.02		)
Total Basic Earnings (Loss) Per Share	$	0.52	$	(0.01	)	$	(1.77	)	$	0.39
Dilutive
Income (Loss) from Continuing Operations	$	0.52	$	(0.01	)	$	(1.77	)	$	0.41
Loss from Discontinued Operations	—		—			—			(0.02		)
Total Dilutive Earnings (Loss) Per Share	$	0.52	$	(0.01	)	$	(1.77	)	$	0.39

Dividends Paid Per Share	$	0.01	$	0.0625		$	0.135		$	0.1875

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended						Nine Months Ended
(Dollars in thousands)	September 30,						September 30,
(Unaudited)	2015			2014			2015			2014
Net Income (Loss)	$	125,470		$	(1,645	)	$	(398,801	)	$	89,424
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $29,720, ($107,383), $24,935, ($108,154))	(49,353		)	184,154			(40,036		)	185,475
Net Increase (Decrease) in the Value of Cash Flow Hedges (Net of tax: $-, ($25,722), $-, $13,161)	—			39,151			—			(20,032		)
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $11,807, $12,084, $35,123, ($5,509))	(20,602		)	(19,510		)	(60,720		)	3,754

Other Comprehensive (Loss) Income	(69,955		)	203,795			(100,756		)	169,197

Comprehensive Income (Loss)	55,515			202,150			(499,557		)	258,621

Less: Comprehensive Income Attributable to Noncontrolling Interest	6,490			—			6,490			—

Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	49,025		$	202,150		$	(506,047	)	$	258,621

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands)	September 30, 2015		December 31, 2014
ASSETS
Current Assets:
Cash and Cash Equivalents	$	83,019	$	176,989
Accounts and Notes Receivable:
Trade	237,896		259,817
Other Receivables	139,840		347,146
Inventories	112,950		101,873
Deferred Income Taxes	78,501		66,569
Recoverable Income Taxes	64,693		20,401
Prepaid Expenses	253,562		193,555
Total Current Assets	970,461		1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	15,533,716		14,674,777
Less—Accumulated Depreciation, Depletion and Amortization	5,774,736		4,512,305
Total Property, Plant and Equipment—Net	9,758,980		10,162,472
Other Assets:
Investment in Affiliates	210,092		152,958
Other	245,833		277,750
Total Other Assets	455,925		430,708
TOTAL ASSETS	$	11,185,366	$	11,759,530

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands, except per share data)	September 30, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	331,958		$	531,973
Current Portion of Long-Term Debt	12,413			13,016
Short-Term Notes Payable	945,000			—
Other Accrued Liabilities	578,332			602,972
Total Current Liabilities	1,867,703			1,147,961
Long-Term Debt:
Long-Term Debt	2,739,291			3,236,422
Capital Lease Obligations	37,387			39,456
Total Long-Term Debt	2,776,678			3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	69,947			325,592
Postretirement Benefits Other Than Pensions	632,049			703,680
Pneumoconiosis Benefits	118,532			116,941
Mine Closing	300,883			306,789
Gas Well Closing	183,423			175,369
Workers’ Compensation	75,714			75,947
Salary Retirement	90,459			109,956
Reclamation	34,088			33,788
Other	148,040			158,171
Total Deferred Credits and Other Liabilities	1,653,135			2,006,233
TOTAL LIABILITIES	6,297,516			6,430,072
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,053,634 Issued and Outstanding at September 30, 2015; 230,265,463 Issued and Outstanding at December 31, 2014	2,294			2,306
Capital in Excess of Par Value	2,430,834			2,424,102
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,551,721			3,054,150
Accumulated Other Comprehensive Loss	(251,856		)	(151,100		)
Total CONSOL Energy Inc. Stockholders’ Equity	4,732,993			5,329,458
Noncontrolling Interest	154,857			—
TOTAL EQUITY	4,887,850			5,329,458
TOTAL LIABILITIES AND EQUITY	$	11,185,366		$	11,759,530

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 Loss			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest		Total Equity
December 31, 2014	$	2,306		$	2,424,102		$	3,054,150		$	(151,100	)	$	5,329,458		$	—	$	5,329,458
(Unaudited)
Net (Loss) Income	—			—			(405,291		)	—			(405,291		)	6,490		(398,801		)
Other Comprehensive Loss	—			—			—			(100,756		)	(100,756		)	—		(100,756		)
Comprehensive (Loss) Income	—			—			(405,291		)	(100,756		)	(506,047		)	6,490		(499,557		)
Issuance of Common Stock	10			8,278			—			—			8,288			—		8,288
Retirement of Common Stock (2,213,100 shares)	(22		)	(17,683		)	(53,969		)	—			(71,674		)	—		(71,674		)
Treasury Stock Activity	—			—			(12,178		)	—			(12,178		)	—		(12,178		)
Tax Cost From Stock-Based Compensation	—			(3,699		)	—			—			(3,699		)	—		(3,699		)
Amortization of Stock-Based Compensation Awards	—			19,836			—			—			19,836			—		19,836
Noncontrolling Interest	—			—			—			—			—			148,367		148,367
Dividends ($0.1350 per share)	—			—			(30,991		)	—			(30,991		)	—		(30,991		)
Balance at September 30, 2015	$	2,294		$	2,430,834		$	2,551,721		$	(251,856	)	$	4,732,993		$	154,857	$	4,887,850

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



(Dollars in thousands)	Nine Months Ended
(Unaudited)	September 30,
Operating Activities:	2015			2014
Net (Loss) Income	$	(398,801	)	$	89,424
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Operating Activities:
Net Loss from Discontinued Operations	—			5,687
Depreciation, Depletion and Amortization	458,080			415,680
Impairment of Exploration and Production Properties	828,905			—
Non-Cash Other Post-Employment Benefits	(151,871		)	(35,633		)
Stock-Based Compensation	19,849			32,514
Gain on Sale of Assets	(54,604		)	(12,615		)
Loss on Debt Extinguishment	67,751			95,267
Unrealized Gain on Commodity Derivative Instruments	(134,205		)	—
Deferred Income Taxes	(281,705		)	6,540
Equity in Earnings of Affiliates	(38,838		)	(38,477		)
Return on Equity Investment	31,111			47,424
Changes in Operating Assets:
Accounts and Notes Receivable	77,272			(64,241		)
Inventories	(11,077		)	12,542
Prepaid Expenses	103,091			3,178
Changes in Other Assets	22,913			(14,339		)
Changes in Operating Liabilities:
Accounts Payable	(123,376		)	151,829
Accrued Interest	63,879			32,698
Other Operating Liabilities	(73,515		)	116,474
Changes in Other Liabilities	(9,945		)	10,703
Other	9,369			16,450
Net Cash Provided by Continuing Operations	404,283			871,105
Net Cash Used in Discontinued Operating Activities	—			(20,934		)
Net Cash Provided by Operating Activities	404,283			850,171
Cash Flows from Investing Activities:
Capital Expenditures	(895,156		)	(1,174,607		)
Proceeds from Sales of Assets	83,044			141,136
Net Investments In Equity Affiliates	(70,224		)	108,532
Net Cash Used in Investing Activities	(882,336		)	(924,939		)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	945,000			(11,736		)
Payments on Miscellaneous Borrowings	(1,562		)	(4,169		)
Payments on Long-Term Notes, including Redemption Premium	(1,263,719		)	(1,819,005		)
Net Proceeds from Revolver - MLP	180,000			—
Proceeds from Sale of MLP Interest	148,359			—
Proceeds from Issuance of Long-Term Notes	492,760			1,859,920
Tax Benefit from Stock-Based Compensation	208			2,478
Dividends Paid	(30,991		)	(43,119		)
Issuance of Common Stock	8,288			13,403
Purchases of Treasury Stock	(71,674		)	—
Debt Issuance and Financing Fees	(22,586		)	(24,861		)
Net Cash Provided By (Used in) Financing Activities	384,083			(27,089		)
Net Decrease in Cash and Cash Equivalents	(93,970		)	(101,857		)
Cash and Cash Equivalents at Beginning of Period	176,989			327,420
Cash and Cash Equivalents at End of Period	$	83,019		$	225,563

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 nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2014 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, 2014 included in CONSOL Energy Inc.'s Annual Report on Form 10-K.

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2014, with no effect on previously reported net income or stockholders' equity.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Anti-Dilutive Options	3,650,864	4,116,136	3,650,864	359,488
Anti-Dilutive Restricted Stock Units	785,585	1,278,078	1,394,115	—
Anti-Dilutive Performance Share Units	—	287,226	—	—
Anti-Dilutive Performance Stock Options	802,804	802,804	802,804	—
	5,239,253	6,484,244	5,847,783	359,488

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Options	—	7,456	363,620	655,568
Restricted Stock Units	90,055	6,034	576,562	396,836
Performance Share Units	—	—	497,134	378,971
	90,055	13,490	1,437,316	1,431,375

No options were exercised during the three months ended September 30, 2015. The weighted average exercise price per share of the options exercised during the three months ended September 30, 2014 was $22.75. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2015 and 2014 was $22.78 and $20.44, respectively.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015			2014
Income (Loss) from Continuing Operations	$	125,470	$	(1,645	)	$	(398,801	)	$	95,111
Loss from Discontinued Operations	—		—			—			(5,687		)
Net Income	$	125,470	$	(1,645	)	$	(398,801	)	$	89,424
Net Income Attributable to Noncontrolling Interest	6,490		—			6,490			—
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	118,980	$	(1,645	)	$	(405,291	)	$	89,424
Weighted Average Shares of Common Stock Outstanding:
Basic	229,036,172		230,174,256			229,230,571			229,922,936
Effect of Stock-Based Compensation Awards	315,955		—			—			1,479,976
Dilutive	229,352,127		230,174,256			229,230,571			231,402,912
Earnings (Loss) per Share:
Basic (Continuing Operations)	$	0.52	$	(0.01	)	$	(1.77	)	$	0.41
Basic (Discontinued Operations)	—		—			—			(0.02		)
Total Basic	$	0.52	$	(0.01	)	$	(1.77	)	$	0.39

Dilutive (Continuing Operations)	$	0.52	$	(0.01	)	$	(1.77	)	$	0.41
Dilutive (Discontinued Operations)	—		—			—			(0.02		)
Total Dilutive	$	0.52	$	(0.01	)	$	(1.77	)	$	0.39

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



	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2014	$	121,521		$	(272,621	)	$	(151,100	)
Other comprehensive income before reclassifications	—			34,566			34,566
Amounts reclassified from Accumulated Other Comprehensive Income	(60,720		)	(74,602		)	(135,322		)
Current period other comprehensive loss	(60,720		)	(40,036		)	(100,756		)
Balance at September 30, 2015	$	60,801		$	(312,657	)	$	(251,856	)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Derivative Instruments (Note 13)
Natural Gas Price Swaps and Options	$	(32,409	)	$	(31,594	)	$	(95,843	)	$	9,263
Tax Expense (Benefit)	11,807			12,084			35,123			(5,509		)
Net of Tax	$	(20,602	)	$	(19,510	)	$	(60,720	)	$	3,754
Actuarially Determined Long-Term Liability Adjustments (Note 4 and Note 5)
Amortization of Prior Service Costs	$	(133,851	)	$	(2,542	)	$	(203,159	)	$	(7,625	)
Recognized Net Actuarial Loss	41,755			11,198			80,497			32,705
Curtailment Loss (Gain)	5			(36,182		)	5			(36,182		)
Settlement loss	3,132			4,785			3,132			25,492
Total	(88,959		)	(22,741		)	(119,525		)	14,390
Tax Expense (Benefit)	33,436			8,376			44,923			(5,300		)
Net of Tax	$	(55,523	)	$	(14,365	)	$	(74,602	)	$	9,090

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In September 2015, CONSOL Energy sold its 49% interest in Western Allegheny Energy (WAE), a joint venture with Rosebud Mining Company engaged in coal mining activities in Pennsylvania. CONSOL Energy received $76,297 in cash and a $2,136 reduction in certain liabilities. During the quarter, CONSOL Energy also received a cash distribution of $10,780 from WAE. The net gain on the sale was $48,468 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

In December 2014, CNX Gas Company LLC (CNX Gas Company), a wholly-owned subsidiary of CONSOL Energy, finalized an agreement with Columbia Energy Ventures (CEVCO) to sublease from CEVCO approximately 20,000 acres of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. Up-front bonus consideration of up to $96,106 will be paid by CONSOL Energy over the next five years as drilling occurs in addition to royalties, of which $49,533 was recorded in Other Current Liabilities and $40,286 was recorded on a discounted basis in Other Long-term Liabilities. In the nine months ended September 30, 2015, CONSOL Energy made payments to CEVCO totaling $50,970. As of September 30, 2015, the amount recorded in Other Current Liabilities was $11,998 and Other Long-term Liabilities was $26,851.

In December 2014, CONSOL Energy completed the sale of its industrial supplies subsidiary to an unrelated third party for net proceeds of approximately $51,000, of which $44,035 was received and included in cash flows from investing activities during the year ended December 31, 2014. In connection with the sale, CONSOL Energy signed a supply agreement under which, among other things, it will continue to purchase certain goods exclusively from the new entity for a period of at least three years. CONSOL Energy could also receive up to an additional $6,000 of cash consideration in the future, which has not been recognized in the consolidated financial statements as it is subject to future events.

In March 2014, CONSOL Energy completed a sale-leaseback of longwall shields for the Harvey Mine. Cash proceeds for the sale offset the basis of $75,357; therefore, no gain or loss was recognized on the sale. The five-year lease has been accounted for as an operating lease.

In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unit of Dominion Resources Inc. The acreage, which is associated with Dominion’s Fink-Kennedy, Lost Creek, and Racket Newberne gas storage fields in West Virginia, lies in the northern portion of Lewis County and the southern portion of Harrison County. CONSOL Energy anticipates that over one-half of the acres will have wet gas. CONSOL Energy has acquired the gas rights to both the Marcellus Shale and the Upper Devonian formations in the storage fields. Consideration of up to $190,000 will be paid by CONSOL Energy in two installments: 50% was paid at closing and the remaining balance is due over time as the acres are drilled. In addition, CONSOL Energy will pay an overriding royalty to Dominion Resources based on a sliding scale. Finally, CONSOL Energy has committed to be an anchor shipper on Dominion’s transmission system, with the specific terms to be negotiated at a future date. CONSOL Energy paid $91,243 in 2013 related to this transaction. In the nine months ended September 30, 2014, CONSOL Energy made an additional bonus payment of $16,000 to Dominion Transmission. Noble Energy Inc., our joint venture partner, acquired 50% of the acres and reimbursed CONSOL Energy for 50% of the associated payments.

In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which included all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). CONSOL Energy retained overriding royalty interests in certain reserves sold in the transaction. Murray Energy also assumed $2,050,656 of CONSOL Energy's employee benefit obligations valued as of December 5, 2013 and its UMWA 1974 Pension Trust obligations. Murray Energy is primarily liable for all 1993 Coal Act liabilities. Cash proceeds of $825,285 were received related to this transaction, which were net of $24,715 in transaction fees. A pre-tax gain of $1,035,346 was included in Income from Discontinued Operations on the Consolidated Statement of Income. In the first quarter of 2014, there was a pre-tax reduction in gain on sale of $7,044 related to the estimated working capital adjustment and various other miscellaneous items.

NOTE 3—MISCELLANEOUS OTHER INCOME:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Equity in Earnings of Affiliates	$	15,588	$	18,284	$	38,835	$	39,796
Rental Income	9,440		9,731		28,446		35,336
Right of Way Issuance	5,097		2,485		13,047		4,898
Royalty Income	4,848		5,003		12,995		14,758
Gathering Revenue	1,590		3,636		10,064		24,386
Coal Contract Settlement	—		—		—		30,000
Other	2,077		1,645		9,013		16,641
Total Other Income	$	38,640	$	40,784	$	112,400	$	165,815

NOTE 4—COMPONENTS OF PENSION AND OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:

Components of net periodic benefit costs for the three and nine months ended September 30, 2015 and 2014 are as follows:



	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	2,162		$	4,834		$	6,862		$	13,625		$	—		$	2,331		$	—		$	6,994
Interest cost	8,042			8,667			25,202			26,812			6,677			12,096			20,561			36,290
Expected return on plan assets	(12,903		)	(12,829		)	(38,282		)	(38,342		)	—			—			—			—
Amortization of prior service credits	(166		)	(346		)	(518		)	(1,038		)	(133,685		)	(2,196		)	(202,641		)	(6,588		)
Recognized net actuarial loss	5,335			6,444			19,215			18,441			37,713			6,369			65,161			19,106
Settlement loss	3,132			4,785			3,132			25,492			—			—			—			—
Curtailment loss (gain)	5			(549		)	5			(549		)	—			(35,633		)	—			(35,633		)
Net periodic cost (benefit)	$	5,607		$	11,006		$	15,616		$	44,441		$	(89,295	)	$	(17,033	)	$	(116,919	)	$	20,169

For the nine months ended September 30, 2015, $8,366 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 2015.

On September 30, 2014, the qualified pension plan was remeasured to reflect an announced plan amendment that would reduce future accruals of pension benefits as of January 1, 2015. The plan amendment called for a hard freeze of the qualified defined benefit pension plan on January 1, 2015 for employees who were under age 40 or had less than 10 years of service as of September 30, 2014. On January 1, 2015, the Company began contributing an extra 3% of eligible compensation into the 401(k) plan accounts for these affected employees. Employees who were age 40 or over and had at least 10 years of service would continue in the defined benefit pension plan unchanged. The modifications to the pension plan resulted in a $21,624 reduction in the pension liability with a corresponding adjustment of $13,659 in Other Comprehensive Income, net of $7,965 in deferred taxes. Additionally, a curtailment gain of $549 was recognized with a corresponding adjustment of $347 in Other Comprehensive Income, net of $202 in deferred taxes.

On August 31, 2015, the qualified pension plan was remeasured to reflect another announced plan amendment that will reduce future accruals of pension benefits as of January 1, 2016. The plan amendment calls for a hard freeze of the qualified defined benefit pension plan on January 1, 2016 for all remaining participants in the plan. The modifications to the pension plan resulted in a $26,352 reduction in the pension liability with a corresponding adjustment of $16,448 in Other Comprehensive Income, net of $9,904 in deferred taxes. Additionally, a curtailment loss of $5 was recognized with a corresponding adjustment

of $3 in Other Comprehensive Income, net of $2 in deferred taxes. The amendment resulted in a remeasurement of the qualified pension plan at August 31, 2015. The remeasurement resulted in a change to the discount rate to 4.40% from 4.07% used at December 31, 2014. The remeasurement increased the pension liability by $17,793 with a corresponding adjustment of $11,106 in Other Comprehensive Income, net of $6,687 in deferred taxes.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three and nine months ended September 30, 2015. Accordingly, CONSOL Energy recognized settlement expense of $3,132 for the three and nine months ended September 30, 2015 in Other Costs - Miscellaneous Operating Expense 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 accounting was triggered in July 2015, resulting in a remeasurement at July 31. The July 31, 2015 remeasurement resulted in a change to the discount rate to 4.28% from 4.07% at December 31, 2014. The remeasurement reduced the pension liability by $1,328. The July settlement and corresponding remeasurement of the pension plan resulted in an increase of $2,784 in Other Comprehensive Income, net of $1,676 in deferred taxes. If CONSOL Energy incurs additional lump sum distributions from the plan in the fourth quarter of 2015, additional settlement charges will be recorded.

Lump sum payments also exceeded the settlement threshold during the three and nine months ended September 30, 2014. Accordingly, CONSOL Energy recognized settlement expense of $4,785 and $25,492 for the three and nine months ended September 30, 2014 in Other Costs - Miscellaneous Operating Expense 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 accounting was initially triggered in May 2014, resulting in a remeasurement at May 31, 2014. Additional lump sum distributions during June and September 2014 resulted in remeasurements at June 30, 2014 and September 30, 2014. The September 30, 2014 remeasurement used a discount rate of 4.33%, an increase from 4.26% used at June 30, 2014. The September remeasurement increased the pension liability by $13,152. The September settlement and corresponding remeasurement of the pension plan resulted in a decrease of $5,285 in Other Comprehensive Income, net of $3,082 in deferred taxes. The May 31, 2014 and June 30, 2014 remeasurements used a discount rate of 4.26%, a decrease from 4.87% used at December 31, 2013. The May remeasurement increased the pension liability by $41,527. The May settlement and corresponding remeasurement of the pension plan resulted in a decrease of $14,193 in Other Comprehensive Income, net of $8,276 in deferred taxes. The June remeasurement decreased the pension liability by $6,490. The June settlement and corresponding remeasurement of the pension plan resulted in an increase of $5,141 in Other Comprehensive Income, net of $2,998 in deferred taxes.

In the third quarter of 2015, CONSOL Energy remeasured its pension plan as a result of the previously discussed plan amendment. In conjunction with this remeasurement, the method used to estimate the service and interest components of net periodic benefit cost for pension was changed. This change will also be made to other postretirement benefits during the fourth quarter during the annual remeasurement of that plan. This change compared to the previous method resulted in a decrease in the service and interest components for pension cost in the third quarter. Historically, CONSOL Energy estimated these service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. CONSOL Energy has elected to utilize a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. This change was made to provide a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This change does not affect the measurement of the total benefit obligations or the annual net periodic benefit cost as the change in the service and interest costs is completely offset in the actuarial (gain) loss reported. CONSOL Energy has accounted for this change as a change in accounting estimate that is inseparable from a change in accounting principle and accordingly has accounted for it prospectively.

On September 30, 2014, the salaried OPEB plan and Production and Maintenance (P&M) OPEB plan were remeasured to reflect an announced plan amendment that would reduce retiree medical and life insurance benefits as of September 30, 2014. Effective September 30, 2014, no retiree medical or life benefits were to be provided to active employees. Retirees as of September 30, 2014 were to continue in the OPEB plans through December 31, 2019, and coverage thereafter was to be eliminated (see below for information on an additional amendment made to these plans in 2015). The Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree medical and life benefits were eliminated by the changes to the OPEB plan. These cash payments are not considered to be post-retirement benefits, and as such, they are not included in the actuarial calculations related to the OPEB plans. The amendment to the OPEB plan resulted in a $315,439 reduction in the OPEB liability with a corresponding adjustment of $199,252 in Other Comprehensive Income, net of $116,187 in deferred taxes. A curtailment gain of $35,633 was recognized in September 2014 with a corresponding adjustment of $22,508 in Other Comprehensive Income, net of $13,125 in deferred taxes. The amendment resulted in a remeasurement of the OPEB plan at

September 30, 2014. The remeasurement resulted in a change to the discount rate to 1.92% for the P&M OPEB plan and 1.84% for the Salaried OPEB plan from 4.88% used at December 31, 2013. The remeasurement increased the OPEB liability by $9,634 with a corresponding decrease of $6,086 in Other Comprehensive Income, net of $3,548 in deferred taxes.

On May 31, 2015, the Salaried OPEB and Production and Maintenance (P&M) OPEB plans were remeasured to reflect another plan amendment. Retirees will continue in the Salaried and P&M OPEB plans until December 31, 2015, and coverage thereafter will be eliminated. The amendment to the OPEB plan resulted in a $43,598 reduction in the OPEB liability with a corresponding increase of $27,716 in Other Comprehensive Income, net of $15,882 in deferred taxes. The amendment resulted in a remeasurement of the OPEB plan at May 31, 2015. The remeasurement resulted in a change to the discount rate to 1.60% for the Salaried OPEB plan and 1.65% for the P&M OPEB plan from 1.78% and 1.84%, respectively, used at December 31, 2014. The remeasurement decreased the OPEB liability by $1,070 with a corresponding increase of $680 in Other Comprehensive Income, net of $390 in deferred taxes. CONSOL Energy expects to recognize income of $235,541 related to amortization of prior service credit, coupled with recognition of actuarial losses in Operating and Other Costs - Coal in the Consolidated Statements of Income for the year ended December 31, 2015 as a result of the changes made to the Salaried and P&M OPEB plans.

CONSOL Energy does not expect to contribute to the other post-employment benefit plan in 2015. The Company intends to pay benefit claims as they become due. For the nine months ended September 30, 2015, $40,547 of other post-employment benefits have been paid.

NOTE 5—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:

Components of net periodic benefit costs for the three and nine months ended September 30, 2015 and 2014 are as follows:



	CWP												Workers' Compensation
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	1,623		$	1,419		$	4,868		$	4,255		$	2,347		$	2,446		$	7,042		$	7,336
Interest cost	1,279			1,384			3,837			4,153			799			894			2,396			2,683
Amortization of actuarial gain	(1,394		)	(1,549		)	(4,182		)	(4,647		)	(8		)	(96		)	(23		)	(287		)
State administrative fees and insurance bond premiums	—			—			—			—			888			999			2,764			3,039
Net periodic benefit cost	$	1,508		$	1,254		$	4,523		$	3,761		$	4,026		$	4,243		$	12,179		$	12,771

CONSOL Energy does not expect to contribute to the CWP plan in 2015. The Company intends to pay benefit claims as they become due. For the nine months ended September 30, 2015, $8,369 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2015. The Company intends to pay benefit claims as they become due. For the nine months ended September 30, 2015, $12,540 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 6—INCOME TAXES:

For the three months ended September 30, 2015, the company recognized income tax expense from continuing operations of $58,143 and for the nine months ended September 30, 2015 the company recognized an income tax benefit from continuing operations of $259,389. The effective tax rate differed from the statutory tax rate primarily due to the deduction for percentage depletion in excess of cost depletion related to the company’s coal operations. Additionally, for the three and nine months ended September 30, 2015, CONSOL Energy recognized tax expense primarily as a result of a change in estimate at the time the 2014 tax return was filed. The tax expense consists of $26,565 related to decreased percentage depletion deductions offset by $4,867 of tax benefit related to changes in various other estimates. The change in estimate related to the percentage depletion deduction decreased due to the company electing bonus depreciation on the 2014 U.S. Corporation Income Tax Return which allowed for a current year deduction of 50% of the basis of the assets placed in service in 2014.

For the three months ended September 30, 2014, the Company recognized an income tax benefit from continuing operations of $1,388 and for the nine months ended September 30, 2014 the Company recognized income tax expense from continuing operations of $8,315. The effective tax rate differed from the statutory tax rate primarily due to the deduction for the percentage depletion in the excess of cost depletion related to the Company's coal operations. For the three and nine months ended September 30, 2014, the Company recognized no tax benefit and $8,820, respectively, related to the completion of the Internal Revenue Service audit of tax years 2008 and 2009, and no income tax benefit and $7,766 as a result of changes in estimates of excess percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision. For the three and nine months ended September 30, 2014, the Company recognized no income tax expense and $3,344 related to filing amended state income tax returns due to the completion of the Internal Revenue Service audit of tax years 2008 and 2009.

There were no uncertain tax positions at September 30, 2015 and December 31, 2014. There were no additions to the liability for unrecognized tax benefits during the nine months ended September 30, 2015.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. No interest expense was recognized for the three and nine months ended September 30, 2015. For the three and nine months ended September 30, 2014, $32 of interest expense and $4,866 of interest income was recognized in the Company's Consolidated Statements of Income. The Company had no accrued interest liabilities relating to uncertain tax positions at September 30, 2015 or December 31, 2014.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 30, 2015 and December 31, 2014, CONSOL Energy had no accrued liabilities 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 examinations by tax authorities for the years before 2010. The Internal Revenue Service began its audit of tax years 2010 through 2013 in the second quarter of 2015.

NOTE 7—INVENTORIES:

Inventory components consist of the following:



	September 30, 2015		December 31, 2014
Coal	$	34,666	$	19,242
Supplies	78,284		82,631
Total Inventories	$	112,950	$	101,873

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.

NOTE 8—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of its U.S. subsidiaries were party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. This facility was terminated on July 7, 2015.

CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, bought and sold eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sold all of their eligible trade accounts receivable to CNX Funding Corporation, who in turn sold 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 was included in Accounts and Notes Receivable-Trade in the Consolidated Balance Sheets, was recorded at fair value. Due to a short average collection cycle for such receivables, CONSOL Energy's collection experience history and the composition of the designated pool of trade accounts receivable that were part of this program, the fair value of its retained interest approximated the total amount of the designated pool of accounts receivable. CONSOL Energy serviced the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

CONSOL Energy recorded transactions under the securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral was reported as Accounts Receivable - Securitized and the borrowings were classified as debt in Borrowings under Securitization Facility.

At December 31, 2014, eligible accounts receivable totaled $77,800, outstanding letters of credit were $60,230, and there were no outstanding borrowings. After taking into account outstanding letters of credit and outstanding borrowings, there remained $17,570 in subordinated retained interest at December 31, 2014. These changes were reflected in the Net Cash Used in Financing Activities section of the Consolidated Statement of Cash Flows. The outstanding borrowings at June 30, 2015 were repaid and the outstanding letters of credit at June 30, 2015 were transferred against the revolving credit facility upon termination on July 7, 2015.

NOTE 9—PROPERTY, PLANT AND EQUIPMENT:



	September 30, 2015		December 31, 2014
E&P Property, Plant and Equipment
Intangible drilling cost	$	3,360,325	$	2,798,394
Proven gas properties	1,790,731		1,768,007
Unproven gas properties	1,549,075		1,540,835
Gas gathering equipment	1,122,071		1,088,238
Gas wells and related equipment	838,091		716,748
Other gas assets	123,584		123,539
Gas advance royalties	19,616		20,580
Total E&P Property, Plant and Equipment	$	8,803,493	$	8,056,341
Less: Accumulated Depreciation, Depletion and Amortization	2,599,543		1,523,761
Total E&P Property, Plant and Equipment - Net	$	6,203,950	$	6,532,580

Coal and Other Property, Plant and Equipment:
Coal and other plant and equipment	$	3,821,403	$	3,726,514
Coal properties and surface lands	1,367,003		1,358,306
Airshafts	475,307		468,924
Mine development	412,089		414,501
Coal advance mining royalties	390,756		386,245
Leased coal lands	263,665		263,946
Total Coal and Other Property, Plant and Equipment	$	6,730,223	$	6,618,436
Less: Accumulated Depreciation, Depletion and Amortization	3,175,193		2,988,544
Total Coal and Corporate Property, Plant and Equipment - Net	$	3,555,030	$	3,629,892

Total Company Property, Plant and Equipment	$	15,533,716	$	14,674,777
Less - Total Company Accumulated Depreciation, Depletion and Amortization	5,774,736		4,512,305
Total Company Property, Plant and Equipment - Net	$	9,758,980	$	10,162,472

Impairment of Proven Properties

CONSOL Energy performs a quantitative annual impairment test, during the fourth quarter of each year, over proven properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. During interim periods, management updates these annual tests whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. Throughout the first six months of 2015, spot prices and forward curves for natural gas continued to decline from December 31, 2014 prices, which together with other macro-economic factors in the exploration and production industry were deemed indicators of impairment for all of the Company's natural gas assets. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital.

During the quarter ended June 30, 2015, certain of the Company’s producing gas properties, primarily shallow oil and gas assets, failed the undiscounted cash flow portion of the test. After performing the discounted cash flow portion of the test, CONSOL Energy recorded an impairment of $824,742 in the Impairment of Exploration and Production Properties in the Consolidated Statement of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs,

such as future production levels and operating costs, within the discounted cash flow analysis. The impairment related to approximately 95% of the Company’s shallow oil and gas assets in West Virginia and Pennsylvania.

Impairment of Unproven Properties

CONSOL Energy evaluates capitalized costs of unproven gas properties for recoverability on a prospective basis. Indicators of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proven reserves, the related costs are expensed in the period the determination is made. For the quarter ended June 30, 2015, unproven property impairments relating to the determination that the properties will not yield proven reserves were $4,163 and are included in the Impairment of Exploration and Production Properties in the Consolidated Statement of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. This impairment primarily relates to the court ruling in June 2015 in the state of New York that officially bans hydraulic fracturing.

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 the Company's retained interests.

CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 155,000 net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess is obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. As of September 30, 2015, Hess’ remaining carry obligation is $39,705. For the nine months ended September 30, 2015 and September 30, 2014, Hess' carry payments to CNX Gas Company reduced capital expenditures by $82,863 and $68,081, respectively.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 700,000 net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owns a 50% undivided interest. Under the agreement, as amended, Noble Energy is obligated to pay a total of approximately $1,846,000 in the form of a one-third drilling carry of certain of CONSOL Energy’s working interest obligations as the property is developed, subject to certain limitations. These limitations include the suspension of the carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. The carry was in effect from March 1, 2014, and remained in effect until November 1, 2014 when average natural gas prices fell below $4.00/MMbtu for three consecutive months. The carry continues to be suspended. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of September 30, 2015, Noble Energy’s remaining carry obligation is $1,624,448. For the nine months ended September 30, 2015 and September 30, 2014, Noble's carry payments to CNX Gas Company reduced capital expenditures by $25,578 and $103,044, respectively.

NOTE 10—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's current senior secured credit agreement expires on June 18, 2019. The credit facility allows for up to $2,000,000 of borrowings, which includes a $750,000 letters of credit sub-limit. CONSOL Energy can request an additional $500,000 increase in the aggregate borrowing limit amount.

The current facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy's proved gas reserves. The Company's senior secured credit facility is currently under redetermination and CONSOL Energy expects this process to be finalized in November 2015.

The current facility contains a number of affirmative and negative covenants that limit the Company's 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. In May 2015, the facility was amended to allow, among other things, spinoffs, or other public equity offering transactions, in regard to subsidiaries that own metallurgical coal assets and thermal coal assets, and all arrangements, actions and transactions in connection therewith, including releases of associated entities or assets from the Credit Agreement and any liens granted under the loan documents. The Amendment also permits the incurrence of a term loan facility up to an aggregate principal amount of $600,000 at subsidiaries of the Company that own the thermal coal assets and

the incurrence of a revolving credit facility up to an aggregate principal amount of $300,000 at subsidiaries of the Company that own the metallurgical coal assets.

The facility also requires that CONSOL Energy maintains a minimum interest coverage ratio of 2.50 to 1.00, which is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries, measured quarterly. CONSOL Energy must also maintain a minimum current ratio of 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver, measured quarterly. At September 30, 2015, the interest coverage ratio was 4.86 to 1.00 and the current ratio was 1.96 to 1.00. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and permits CONSOL Energy to separate its E&P and coal businesses if the leverage ratio (which is, essentially, the ratio of debt to EBITDA) of the E&P business immediately after the separation would not be greater than 2.75 to 1.00. The calculation of all of the ratios above exclude CNX Coal Resources LP (CNXC).

At September 30, 2015, the $2,000,000 facility had $945,000 of borrowings outstanding and $280,501 of letters of credit outstanding, leaving $774,499 of unused capacity. At December 31, 2014, the $2,000,000 facility had no borrowings outstanding and $244,418 of letters of credit outstanding, leaving $1,755,582 of unused capacity.

NOTE 11—LONG-TERM DEBT:



	September 30, 2015		December 31, 2014
Debt:
Senior notes due April 2022 at 5.875%, including amortization of bond premium	$	1,855,840	$	1,856,506
Senior notes due April 2023 at 8.00%, including amortization of bond discount	493,213		—
Revolving Credit Facility - CNX Coal Resources LP	180,000		—
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Senior notes due April 2020 at 8.25%, issued at par value	74,470		1,014,800
Senior notes due March 2021 at 6.375%, issued at par value	20,611		250,000
Advance royalty commitments (7.91% weighted average interest rate for September 30, 2015 and December 31, 2014)	13,470		13,473
Other long-term note maturing in 2018 (total value of $3,440 and $4,473 less unamortized discount of $397 and $643 at September 30, 2015 and December 31, 2014, respectively)	3,043		3,830
	2,743,512		3,241,474
Less amounts due in one year *	4,221		5,052
Long-Term Debt	$	2,739,291	$	3,236,422

* Excludes current portion of Capital Lease Obligations of $8,192 and $7,964 at September 30, 2015 and December 31, 2014, respectively.

Accrued interest related to Long-Term Debt of $73,902 and $51,159 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 30, 2015 and December 31, 2014, respectively.

On March 30, 2015, CONSOL Energy closed on the private placement of $500,000 of 8.00% senior notes due 2023 (the "Notes") less $7,240 of unamortized bond discount. The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy used the net proceeds of the sale of the Notes, together with borrowings under its revolving credit facility, to purchase $937,822 of its outstanding 8.25% senior notes due 2020 and $229,176 of its outstanding 6.375% senior notes due 2021. As part of this transaction, $67,734 was included in Loss on Debt Extinguishment on the Consolidated Statements of Income.

On April 7, 2015, CONSOL Energy purchased $2,508 of its outstanding 8.25% senior notes due 2020 and $213 of its outstanding 6.375% senior notes due 2021. As part of this transaction, $17 was included in Loss on Debt Extinguishment on the Consolidated Statements of Income.

On July 7, 2015, CNXC, a consolidated subsidiary of CONSOL Energy, entered into a Credit Agreement for a $400,000 revolving credit facility. As of September 30, 2015, CNXC had $180,000 of borrowings outstanding on the facility. CONSOL Energy is not a guarantor of CNXC's revolving credit facility. See Note 17 - Related Party Transactions for more information.

On April 16, 2014, CONSOL Energy purchased all the 8.00% senior notes that were due in 2017 at an average premium of 1.04%. As part of this transaction, $74,277 was included in Loss on Debt Extinguishment on the Consolidated Statements of Income.

On August 12, 2014, CONSOL Energy closed on an additional $250,000 of its 5.875% senior notes due 2022 at a price equal to 102.75% of the principal amount of the additional notes. CONSOL Energy used $235,200 of the net proceeds of the sale of the additional notes to purchase a portion of the outstanding 8.25% senior notes due in 2020.

NOTE 12—COMMITMENTS AND CONTINGENT LIABILITIES:

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 $641,513.

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

Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of forced-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, and on June 23, 2015 CNX Gas Company filed its Opposition to same. The Court held a hearing on the Renewed Motion on September 18, 2015. The Court took the Motion under advisement and has not yet issued a ruling. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia. The putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that 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. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Court of Appeals for the Fourth Circuit. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, and on June 23, 2015 CNX Gas Company filed its Opposition to same. The Court held a hearing on the Renewed Motion on September 18, 2015. The Court took the Motion under advisement and has not yet issued a ruling. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Clean Water Act - Bailey Mine: The Company received from the U.S. EPA on April 8, 2011, a request for information relating to National Pollutant Discharge Element System (NPDES) Permit compliance at the Company’s Bailey and Enlow Fork Mines. In response, Consol Pennsylvania Coal Company submitted water discharge monitoring and other data to the EPA related to the coal refuse disposal area. In early 2013, the case was referred to the U.S. Department of Justice (DOJ), and Pennsylvania Department of Environmental Protection (PA DEP) also became involved. On December 18, 2014, the DOJ provided the Company a proposed

Consent Decree to resolve certain Clean Water Act and Clean Streams Law claims against CONSOL Energy, Inc. and Consol Pennsylvania Coal Company with respect to the Bailey Mine Complex. The parties continue to negotiate the terms of the proposed Consent Decree. The Company has established an accrual to cover its estimated liability in this matter. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

The following royalty and land rights lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, an accrual may not have 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 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.

Virginia Mine Void Litigation: The Company is currently defending four lawsuits naming Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, and/or CONSOL Energy. All of the lawsuits are pending in the U.S. District Court for the Western District of Virginia. The Complaints seek damages and injunctive relief in connection with the transfer of water from mining activities at Buchanan Mine into void spaces in inactive ICCC mines adjacent to the Buchanan operations, voids ostensibly underlying plaintiffs’ properties. While some of the plaintiffs have an ownership interest in the coal, others have some interest in one or more of the fee, surface, coal, oil/gas or other mineral estates. The suits allege the water storage precludes access to and has damaged coal, impeded coalbed methane gas production and was made without compensation to the property owners. Plaintiffs seek recovery in tort, contract and trespass assumpsit (quasi-contract). The suits each seek damages between $50,000 and in excess of $100,000 plus punitive damages. On October 26, 2015, the Court granted summary judgment in favor of CONSOL Energy in two of the four cases upon its finding that the applicable statute of limitations barred each of the causes of action asserted by the plaintiffs. The Company intends to vigorously defend the remaining two suits.

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 suit further sought a determination that the Pittsburgh No. 8 coal seam does not include the “roof/rider” coal. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled in favor of CNX Gas Company and CONSOL Energy. On March 3, 2014, the Company won summary judgment on Counts 1 through 10 of the Amended Complaint, each relating to the alleged trespass of horizontal CBM wells into strata other than the Pittsburgh 8 Seam. The last remaining Count, seeking to quiet title to approximately 40 acres of Pittsburgh Seam coal, was nonsuited by Plaintiffs, without prejudice, on March 26, 2014. Plaintiffs filed Notices of Appeal with the Pennsylvania Superior Court. On April 22, 2015, the Superior Court issued its decision, affirming each of the orders and judgments entered in favor of CONSOL Energy by the trial court. Plaintiffs have filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court, which has not yet decided whether to grant the appeal.

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. The parties have reached a settlement in principle of this matter, which will be dismissed with prejudice.

At September 30, 2015, 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 the Company 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 in the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	88,632	$	27,434	$	61,198	$	—	$	—
Environmental	4,786		3,058		1,728		—		—
Other	187,082		38,758		148,324		—		—
Total Letters of Credit	280,500		69,250		211,250		—		—
Surety Bonds:
Employee-Related	114,678		114,678		—		—		—
Environmental	543,778		542,932		846		—		—
Other	24,323		24,318		4		1		—
Total Surety Bonds	682,779		681,928		850		1		—
Guarantees:
Coal	58,450		50,100		8,350		—		—
Other	78,153		40,858		15,140		12,484		9,671
Total Guarantees	136,603		90,958		23,490		12,484		9,671
Total Commitments	$	1,099,882	$	842,136	$	235,590	$	12,485	$	9,671

Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray Energy Corporation (Murray Energy). As part of the sales agreement, CONSOL Energy has guaranteed certain equipment lease obligations and coal sales agreements that were assumed by Murray Energy. In the event that Murray Energy would default on the obligations defined in the agreements, CONSOL Energy would be required to perform under the guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions. At September 30, 2015, and December 31, 2014, the fair value of these guarantees were $1,195 and $1,275, respectively, and are included in Other Accrued Liabilities on the Consolidated Balance Sheets. The fair value of certain of the guarantees was determined using CONSOL Energy’s risk-adjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result in a significantly higher or lower fair value measurement. Coal sales agreement guarantees were valued based on an evaluation of coal market pricing compared to contracted sales price and includes an adjustment for nonperformance risk. No other amounts related to financial guarantees and letters of credit are recorded as liabilities in the financial statements. Significant judgment is required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within Level 3 of the fair value hierarchy.

CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and records the fair value, if any, of its guarantees as an obligation in the consolidated financial statements.

CONSOL Energy and CNX Gas Company 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 Sheets. As of September 30, 2015, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	207,816
1 - 3 years	278,404
3 - 5 years	190,761
More than 5 years	553,266
Total Purchase Obligations	$	1,230,247

NOTE 13—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into financial derivative instruments to manage its exposure to commodity price volatility. CONSOL Energy de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future gas commodity hedges on a mark-to-market basis with changes in fair value recorded in current period earnings. In connection with this change, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014 and will reclassify balances to earnings as the underlying physical transactions occur, unless it is no longer probable that the physical transaction will occur at which time the related gains deferred in Other Comprehensive Income (OCI) will be immediately recorded in earnings.

CONSOL Energy is exposed to credit risk in the event of non-performance 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 the Company's counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CONSOL Energy would have to post collateral for instruments in a liabilities position in excess of defined thresholds. All of the Company's 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 by counterparty.

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’s commodity derivative instruments accounted for a total notional amount of production of 367.9 Bcf at September 30, 2015 and are forecasted to settle through 2018. At December 31, 2014, the commodity derivative instruments accounted for a total notional amount of production of 215.9 Bcf. At September 30, 2015, the basis only swaps were for notional amounts of 75.3 Bcf and are forecasted to settle through 2016. At December 31, 2014, the basis only swaps were for notional amounts of 10.6 Bcf.

The gross fair value of CONSOL Energy's derivative instruments at September 30, 2015 and December 31, 2014 were as follows:



Asset Derivative Instruments					Liability Derivative Instruments
	September 30,		December 31,			September 30,		December 31,
	2015		2014			2015		2014
Commodity Derivative Instruments
Prepaid Expense	$	181,744	$	123,676	Other Liabilities	$	888	$	—
Other Assets	52,666		68,656		Other Accrued Liabilities	7,160		—
Total Asset:	$	234,410	$	192,332	Total Liability:	$	8,048	$	—

Basis Only Swaps
Prepaid Expense	$	6,250	$	1,064	Other Liabilities	$	1,628	$	—
Other Assets	447		—		Other Accrued Liabilities	—		327
Total Asset:	$	6,697	$	1,064	Total Liability:	$	1,628	$	327

The change in the fair value of the Company's commodity derivative instruments resulted in a gain of $102,771 being recorded in Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the three months ended September 30, 2015. No gain or loss was recorded for the three months ended September 30, 2014. A gain of $137,032 was recorded to Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the nine months ended September 30, 2015. No gain or loss was recorded for the nine months ended September 30, 2014.

The basis only swaps resulted in a loss of $3,634 being recorded in Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the three months ended September 30, 2015. No gain or loss was recorded for the

three months ended September 30, 2014. A loss of $2,827 was recorded to Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the nine months ended September 30, 2015. No gain or loss was recorded for the nine months ended September 30, 2014.

The derivative instruments in which CONSOL Energy discontinued cash flow hedging had an effect on the Consolidated Statements of Income and the Consolidated Statements of Stockholders' Equity, net of tax, were as follows:



	For the Three Months Ended September 30,
	2015		2014
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	81,403	$	6,574
Gain/(Loss) recognized in Accumulated OCI	—		39,151
Amounts reclassified from Accumulated OCI (Net of tax: $11,807, $12,084)	20,602		19,510
Ending Balance – Accumulated OCI	$	60,801	$	26,215
Gain recognized in Outside Sales for ineffectiveness *	$	—	$	1,850

	For the Nine Months Ended September 30,
	2015		2014
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	121,521	$	42,493
Gain/(Loss) recognized in Accumulated OCI	—		(20,032		)
Amounts reclassified from Accumulated OCI (Net of tax: $35,123, ($5,509))	60,720		(3,754		)
Ending Balance – Accumulated OCI	$	60,801	$	26,215
Gain recognized in Outside Sales for ineffectiveness *	$	—	$	2,713

* No amounts were excluded from effectiveness testing of cash flow hedges.

CONSOL Energy expects to reclassify an additional $17,331, net of tax of $9,931, out of Accumulated Other Comprehensive Income over the remaining period ended December 31, 2015.

NOTE 14—FAIR VALUE OF FINANCIAL INSTRUMENTS:

CONSOL Energy determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use.

The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:

Level One - Quoted prices for identical instruments in active markets.

Level Two - The fair value of the assets and liabilities included in Level Two are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves.

Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Company's third party guarantees are the credit risk of the third party, and the third party surety bond markets. A significant increase or decrease in these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of the Company's Level Three guarantees.

In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

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



	Fair Value Measurements at September 30, 2015						Fair Value Measurements at December 31, 2014
Description	(Level 1)		(Level 2)		(Level 3)		(Level 1)		(Level 2)		(Level 3)
Gas Derivatives	$	—	$	231,431	$	—	$	—	$	193,069	$	—
Murray Energy Guarantees	$	—	$	—	$	1,195	$	—	$	—	$	1,275

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 Consolidated Balance Sheets for cash and cash equivalents approximates its fair value due to the short-term maturity of these instruments.

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

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

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



	September 30, 2015						December 31, 2014
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	83,019		$	83,019		$	176,989		$	176,989
Short-Term Notes Payable	$	(945,000	)	$	(945,000	)	$	—		$	—
Long-Term Debt	$	(2,743,512	)	$	(1,938,413	)	$	(3,241,474	)	$	(3,169,154	)

Cash and cash equivalents represent highly-liquid instruments and constitute Level 1 fair value measurements. Certain of the Company’s debt is actively traded on a public market and, as a result, constitute Level 1 fair value measurements. The portion of the Company’s debt obligations that are not actively traded are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

NOTE 15—SEGMENT INFORMATION:

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Coal. The principal activity of the E&P division, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division's reportable segments are Marcellus, Utica, Coalbed Methane, and Other Gas. The Other Gas segment is primarily related to shallow oil and gas production as well as Upper Devonian Shale, and includes the Company's purchased gas activities and general and administrative activities, as well as various other activities assigned to the E&P division but not allocated to each individual well type.

The principal activities of the Coal division, which includes three reportable segments, 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's reportable segments are Pennsylvania (PA) Operations, Virginia (VA) Operations, and Other Coal. Each of these reportable segments includes a number of operating segments (individual mines). For the three and nine months ended September 30, 2015, the PA Operations aggregated segment includes the following mines: Bailey Mine, Enlow Fork Mine, and Harvey Mine and the corresponding preparation plant facilities. For the three and nine months ended September 30, 2015, the VA Operations aggregated segment includes the Buchanan Mine and the corresponding preparation plant facilities. For the three and nine months ended September 30, 2015, the Other Coal segment includes the Miller Creek Complex, coal terminal operations, the Company's purchased coal activities, idled mine activities and general and administrative activities, as well as various other activities assigned to the Coal division but not allocated to each individual mine.

CONSOL Energy’s All Other division includes expenses from various other corporate activities that are not allocated to the E&P or Coal divisions.

In the preparation of the following information, 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 for E&P and are not allocated between each individual E&P segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy, whereby each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

Industry segment results for the three months ended September 30, 2015 are:



	Marcellus Shale			Utica Shale			Coalbed Methane		Other Gas		Total E&P		PA Operations		VA Operations		Other Coal		Total Coal		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	96,941		$	21,572		$	63,145	$	20,349	$	202,007	$	323,171	$	48,795	$	31,636	$	403,602	$	—		$	—		$	605,609	(A)
Other outside sales	—			—			—		—		—		—		—		5,129		5,129		—			—			5,129
Sales—purchased gas	—			—			—		2,535		2,535		—		—		—		—		—			—			2,535
Sales—production royalty interests	—			—			—		11,545		11,545		—		—		—		—		—			—			11,545
Freight—outside	—			—			—		—		—		1,211		50		1,958		3,219		—			—			3,219
Intersegment transfers	—			—			298		—		298		—		—		—		—		—			(298		)	—
Total Sales and Freight	$	96,941		$	21,572		$	63,443	$	34,429	$	216,385	$	324,382	$	48,845	$	38,723	$	411,950	$	—		$	(298	)	$	628,037
(Loss) Earnings Before Income Taxes	$	(18,444	)	$	(11,230	)	$	8,857	$	71,004	$	50,187	$	132,328	$	16,037	$	45,295	$	193,660	$	(13,885	)	$	(46,349	)	$	183,613	(B)
Segment assets											$	6,843,935	$	2,142,696	$	409,746	$	1,324,081	$	3,876,523	$	204,638		$	260,270		$	11,185,366	(C)
Depreciation, depletion and amortization											$	89,742	$	42,463	$	11,801	$	8,978	$	63,242	$	5		$	—		$	152,989
Capital expenditures											$	209,560	$	34,544	$	9,895	$	3,892	$	48,331	$	1,480		$	—		$	259,371

(A) Included in the Coal segment are sales of $73,999 to Xcoal Energy & Resources and sales of $103,230 to Duke Energy, each comprising over 10% of sales.

(B) Includes equity in earnings of unconsolidated affiliates of $13,467 and $2,121 for E&P and Coal, respectively.

Industry segment results for the three months ended September 30, 2014 are:



	Marcellus Shale		Utica		Coalbed Methane		Other Gas			Total E&P		PA Operations		VA Operations		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	109,850	$	35,846	$	82,914	$	28,748		$	257,358	$	379,641	$	70,931	$	33,388		$	483,960	$	—	$	—		$	741,318		(D)
Other outside sales	—		—		—		—			—		—		—		8,175			8,175		65,498		—			73,673
Sales—purchased gas	—		—		—		1,205			1,205		—		—		—			—		—		—			1,205
Sales—production royalty interests	—		—		—		17,610			17,610		—		—		—			—		—		—			17,610
Freight—outside	—		—		—		—			—		779		102		1,616			2,497		—		—			2,497
Intersegment transfers	—		—		485		—			485		—		—		—			—		23,065		(23,550		)	—
Total Sales and Freight	$	109,850	$	35,846	$	83,399	$	47,563		$	276,658	$	380,420	$	71,033	$	43,179		$	494,632	$	88,563	$	(23,550	)	$	836,303
Earnings (Loss) Before Income Taxes	$	27,328	$	19,776	$	19,790	$	(29,209	)	$	37,685	$	71,623	$	3,397	$	(21,212	)	$	53,808	$	1,085	$	(95,611	)	$	(3,033	)	(E)
Segment assets										$	6,901,696	$	2,085,130	$	363,695	$	1,770,695		$	4,219,520	$	195,351	$	402,368		$	11,718,935		(F)
Depreciation, depletion and amortization										$	82,538	$	44,567	$	11,922	$	9,151		$	65,640	$	487	$	—		$	148,665
Capital expenditures										$	281,641	$	57,449	$	9,068	$	5,202		$	71,719	$	1,952	$	—		$	355,312


(D)	Included in the Coal segment are sales of $107,915 to Duke Energy, which comprise over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $9,991 and $6,974 for E&P and Coal, respectively.

(F) Includes investments in unconsolidated equity affiliates of $92,188, $92,934 and $387 for E&P, Coal and All Other, respectively.

Industry segment results for the nine months ended September 30, 2015 are:



	Marcellus Shale		Utica Shale			Coalbed Methane		Other Gas			Total E&P			PA Operations		VA Operations		Other Coal		Total Coal		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	331,998	$	57,836		$	203,522	$	65,142		$	658,498		$	1,026,603	$	192,626	$	95,519	$	1,314,748	$	—		$	—		$	1,973,246		(G)
Other outside sales	—		—			—		—			—			—		—		24,596		24,596		—			—			24,596
Sales—purchased gas	—		—			—		7,649			7,649			—		—		—		—		—			—			7,649
Sales—production royalty interests	—		—			—		31,774			31,774			—		—		—		—		—			—			31,774
Freight—outside	—		—			—		—			—			6,286		278		7,431		13,995		—			—			13,995
Intersegment transfers	—		—			1,194		—			1,194			—		—		—		—		—			(1,194		)	—
Total Sales and Freight	$	331,998	$	57,836		$	204,716	$	104,565		$	699,115		$	1,032,889	$	192,904	$	127,546	$	1,353,339	$	—		$	(1,194	)	$	2,051,260
Earnings (Loss) Before Income Taxes	$	16,683	$	(23,193	)	$	33,299	$	(791,982	)	$	(765,193	)	$	292,533	$	46,167	$	16,763	$	355,463	$	(15,856	)	$	(232,604	)	$	(658,190	)	(H)
Segment assets											$	6,843,935		$	2,142,696	$	409,746	$	1,324,081	$	3,876,523	$	204,638		$	260,270		$	11,185,366		(I)
Depreciation, depletion and amortization											$	262,356		$	133,786	$	35,398	$	26,523	$	195,707	$	17		$	—		$	458,080
Capital expenditures											$	749,015		$	102,939	$	26,310	$	8,284	$	137,533	$	8,608		$	—		$	895,156

(G) Included in the Coal segment are sales of $282,267 to Xcoal Energy & Resources and sales of $268,278 to Duke Energy, each comprising over 10% of sales.

(H) Includes equity in earnings of unconsolidated affiliates of $31,877 and $6,961 for E&P and Coal, respectively.

(I) Includes investments in unconsolidated equity affiliates of $205,987 and $4,105 for E&P and Coal, respectively.

Industry segment results for the nine months ended September 30, 2014 are:



	Marcellus Shale		Utica		Coalbed Methane		Other Gas			Total E&P		PA Operations		VA Operations		Other Coal			Total Coal		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	339,391	$	56,383	$	259,665	$	97,960		$	753,399	$	1,226,666	$	222,701	$	105,572		$	1,554,939	$	—		$	—		$	2,308,338	(J)
Other outside sales	—		—		—		—			—		—		—		28,685			28,685		184,362			—			213,047
Sales—purchased gas	—		—		—		6,183			6,183		—		—		—			—		—			—			6,183
Sales—production royalty interests	—		—		—		62,590			62,590		—		—		—			—		—			—			62,590
Freight—outside	—		—		—		—			—		14,931		614		7,006			22,551		—			—			22,551
Intersegment transfers	—		—		1,937		—			1,937		—		—		—			—		62,411			(64,348		)	—
Total Sales and Freight	$	339,391	$	56,383	$	261,602	$	166,733		$	824,109	$	1,241,597	$	223,315	$	141,263		$	1,606,175	$	246,773		$	(64,348	)	$	2,612,709
Earnings (Loss) Before Income Taxes	$	121,197	$	25,042	$	71,358	$	(78,993	)	$	138,604	$	336,692	$	2,626	$	(52,743	)	$	286,575	$	(1,811	)	$	(319,942	)	$	103,426	(K)
Segment assets										$	6,901,696	$	2,085,130	$	363,695	$	1,770,695		$	4,219,520	$	195,351		$	402,368		$	11,718,935	(L)
Depreciation, depletion and amortization										$	225,766	$	124,367	$	35,304	$	28,734		$	188,405	$	1,509		$	—		$	415,680
Capital expenditures										$	852,097	$	286,497	$	20,413	$	11,129		$	318,039	$	4,471		$	—		$	1,174,607


(J)	Included in the Coal segment are sales of $297,836 to Duke Energy, which comprise over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $22,801, $17,039 and $(1,363) for E&P, Coal and All Other, respectively.

(L) Includes investments in unconsolidated equity affiliates of $92,188, $92,934 and $387 for E&P, Coal and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings (Loss) Before Income Taxes:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014
Segment Earnings (Loss) Before Income Taxes for total reportable business segments	$	243,847		$	91,493		$	(409,730	)	$	425,179
Segment (Loss) Earnings Before Income Taxes for all other businesses	(13,885		)	1,085			(15,856		)	(1,811		)
Interest expense, net (M)	(48,558		)	(55,397		)	(150,187		)	(170,539		)
Other corporate items (M)	2,209			(19,224		)	(14,666		)	(54,136		)
Loss on debt extinguishment	—			(20,990		)	(67,751		)	(95,267		)
Earnings (Loss) Before Income Taxes	$	183,613		$	(3,033	)	$	(658,190	)	$	103,426



Total Assets:	September 30,
Total Assets:	2015		2014
Segment assets for total reportable business segments	$	10,720,458	$	11,121,216
Segment assets for all other businesses	204,638		195,351
Items excluded from segment assets:
Cash and other investments (M)	82,932		193,325
Recoverable income taxes	64,693		41,971
Deferred tax assets	78,501		127,731
Bond issuance costs	34,144		39,341
Total Consolidated Assets	$	11,185,366	$	11,718,935

_________________________

(M) Excludes amounts specifically related to the E&P segment.

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $74,470, 8.250% per annum senior notes due April 1, 2020, the $20,611, 6.375% per annum senior notes due March 1, 2021, the $1,855,840, 5.875% per annum senior notes due April 15, 2022, and the $493,213, 8.000% per annum senior notes due April 1, 2023 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally, guaranteed by certain 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, CNX Coal Resources LP (CNXC), a non-guarantor subsidiary, and the remaining guarantor and non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the Three Months Ended September 30, 2015 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		CNXC Non-Guarantor		Other Subsidiary Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	202,304	$	—	$	—	$	—		$	(297	)	$	202,007
Unrealized Gain (Loss) on Commodity Derivative Instruments	—			99,137		—		—		—			—			99,137
Coal Sales	—			—		338,967		64,635		—			—			403,602
Other Outside Sales	—			—		5,129		—		—			—			5,129
Production Royalty Interests and Purchased Gas Sales	—			14,080		—		—		—			—			14,080
Freight-Outside Coal	—			—		2,977		242		—			—			3,219
Miscellaneous Other Income	156,955			16,285		22,263		264		(171		)	(156,956		)	38,640
Gain (Loss) on Sale of Assets	—			890		47,223		11		—			—			48,124
Total Revenue and Other Income	156,955			332,696		416,559		65,152		(171		)	(157,253		)	813,938
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			26,454		—		—		—			—			26,454
Transportation, Gathering and Compression	—			92,606		—		—		—			—			92,606
Production, Ad Valorem, and Other Fees	—			8,475		—		—		—			—			8,475
Direct Administrative and Selling	—			10,711		—		—		—			—			10,711
Depreciation, Depletion and Amortization	—			89,742		—		—		—			—			89,742
Exploration and Production Related Other Costs	—			3,332		—		—		15			(15		)	3,332
Production Royalty Interests and Purchased Gas Costs	—			10,989		—		—		—			—			10,989
Other Corporate Expenses	—			26,986		—		—		—			—			26,986
General and Administrative	—			12,513		—		—		—			—			12,513
Total Exploration and Production Costs	—			281,808		—		—		15			(15		)	281,808
Coal Costs
Operating and Other Costs	1,972			—		137,336		34,167		—			(297		)	173,178
Royalties and Production Taxes	—			—		16,547		2,554		—			—			19,101
Direct Administrative and Selling	—			—		6,989		1,236		—			—			8,225
Depreciation, Depletion and Amortization	154			—		54,657		8,431		—			—			63,242
Freight Expense	—			—		2,977		242		—			—			3,219
General and Administrative Costs	—			—		5,508		1,969		—			—			7,477
Other Corporate Expenses	—			—		10,680		—		—			—			10,680
Total Coal Costs	2,126			—		234,694		48,599		—			(297		)	285,122
Other Costs
Miscellaneous Operating Expense	14,571			—		217		—		44			—			14,832
Depreciation, Depletion and Amortization	—			—		5		—		—			—			5
Interest Expense	44,385			701		1,587		1,888		—			(3		)	48,558
Total Other Costs	58,956			701		1,809		1,888		44			(3		)	63,395
Total Costs And Expenses	61,082			282,509		236,503		50,487		59			(315		)	630,325
(Loss) Earnings Before Income Tax	95,873			50,187		180,056		14,665		(230		)	(156,938		)	183,613
Income Taxes	(23,107		)	19,841		61,497		—		(88		)	—			58,143
Net Income (Loss)	118,980			30,346		118,559		14,665		(142		)	(156,938		)	125,470
Less: Net Income Attributable to Noncontrolling Interest	—			—		—		—		—			6,490			6,490
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	118,980		$	30,346	$	118,559	$	14,665	$	(142	)	$	(163,428	)	$	118,980

Balance Sheet at September 30, 2015:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non-Guarantor		Other Subsidiary Non-Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	78,974		$	88		$	—		$	3,004	$	953		$	—		$	83,019
Accounts and Notes Receivable:
Trade	—			67,132			147,613			23,151		—			—			237,896
Other Receivables	30,474			104,405			4,549			412		—			—			139,840
Inventories	—			14,967			85,327			12,656		—			—			112,950
Deferred Income Taxes	95,868			(17,367		)	—			—		—			—			78,501
Recoverable Income Taxes	123,719			(59,026		)	—			—		—			—			64,693
Prepaid Expenses	34,042			191,374			23,118			5,028		—			—			253,562
Total Current Assets	363,077			301,573			260,607			44,251		953			—			970,461
Property, Plant and Equipment:
Property, Plant and Equipment	155,971			8,803,493			5,886,477			687,775		—			—			15,533,716
Less-Accumulated Depreciation, Depletion and Amortization	109,783			2,599,543			2,752,834			312,576		—			—			5,774,736
Total Property, Plant and Equipment-Net	46,188			6,203,950			3,133,643			375,199		—			—			9,758,980
Other Assets:
Investment in Affiliates	11,252,610			205,987			—			—		—			(11,248,505		)	210,092
Other	80,876			56,032			93,404			15,521		—			—			245,833
Total Other Assets	11,333,486			262,019			93,404			15,521		—			(11,248,505		)	455,925
Total Assets	$	11,742,751		$	6,767,542		$	3,487,654		$	434,971	$	953		$	(11,248,505	)	$	11,185,366
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	270,498		$	204,456		$	56,678		$	15,302	$	(226,885	)	$	11,909		$	331,958
Accounts Payable (Recoverable)-Related Parties	3,160,775			1,485,416			(4,652,920		)	1,188		17,450			(11,909		)	—
Current Portion of Long-Term Debt	1,557			7,060			3,452			344		—			—			12,413
Short-Term Notes Payable	945,000			—			—			—		—			—			945,000
Other Accrued Liabilities	157,712			116,180			264,459			39,981		—			—			578,332
Total Current Liabilities	4,535,542			1,813,112			(4,328,331		)	56,815		(209,435		)	—			1,867,703
Long-Term Debt:	2,447,048			35,078			114,189			180,363		—			—			2,776,678
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(98,951		)	168,898			—			—		—			—			69,947
Postretirement Benefits Other Than Pensions	—			—			632,049			—		—			—			632,049
Pneumoconiosis Benefits	—			—			117,110			1,422		—			—			118,532
Mine Closing	—			—			294,227			6,656		—			—			300,883
Gas Well Closing	—			122,049			60,580			794		—			—			183,423
Workers’ Compensation	—			—			72,495			3,219		—			—			75,714
Salary Retirement	90,459			—			—			—		—			—			90,459
Reclamation	—			—			34,088			—		—			—			34,088
Other	35,660			86,876			24,899			605		—			—			148,040
Total Deferred Credits and Other Liabilities	27,168			377,823			1,235,448			12,696		—			—			1,653,135
Total CONSOL Energy Inc. Stockholders’ Equity	4,732,993			4,541,529			6,466,348			185,097		210,388			(11,403,362		)	4,732,993
Noncontrolling Interest	—			—			—			—		—			154,857			154,857
Total Liabilities and Equity	$	11,742,751		$	6,767,542		$	3,487,654		$	434,971	$	953		$	(11,248,505	)	$	11,185,366

Income Statement for the Three Months Ended September 30, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			CNXC Non-Guarantor		Other Subsidiary Non-Guarantors		Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	257,844	$	—		$	—	$	—	$	(486	)	$	257,358
Coal Sales	—			—		408,032			75,928		—		—			483,960
Other Outside Sales	—			—		8,175			—		65,498		—			73,673
Production Royalty Interests and Purchased Gas Sales	—			18,815		—			—		—		—			18,815
Freight-Outside Coal	—			—		2,341			156		—		—			2,497
Miscellaneous Other Income	62,288			13,861		24,937			58		2,400		(62,760		)	40,784
Gain (Loss) on Sale of Assets	—			5,488		2,030			3		8		—			7,529
Total Revenue and Other Income	62,288			296,008		445,515			76,145		67,906		(63,246		)	884,616
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			30,005		—			—		—		—			30,005
Transportation, Gathering and Compression	—			68,234		—			—		—		—			68,234
Production, Ad Valorem, and Other Fees	—			8,486		—			—		—		—			8,486
Direct Administrative and Selling	—			14,060		—			—		—		—			14,060
Depreciation, Depletion and Amortization	—			82,538		—			—		—		—			82,538
Exploration and Production Related Other Costs	—			8,045		—			—		—		—			8,045
Production Royalty Interests and Purchased Gas Costs	—			15,751		—			—		—		—			15,751
Other Corporate Expenses	—			13,700		—			—		—		—			13,700
General and Administrative	—			14,874		—			—		—		—			14,874
Total Exploration and Production Costs	—			255,693		—			—		—		—			255,693
Coal Costs
Operating and Other Costs	3,459			—		296,391			45,628		—		(486		)	344,992
Royalties and Production Taxes	—			—		20,079			3,227		—		—			23,306
Direct Administrative and Selling	—			—		9,099			1,583		—		—			10,682
Depreciation, Depletion and Amortization	159			—		56,568			8,913		—		—			65,640
Freight Expense	—			—		2,341			156		—		—			2,497
General and Administrative Costs	—			—		8,016			2,623		—		—			10,639
Other Corporate Expenses	—			—		10,113			—		—		—			10,113
Total Coal Costs	3,618			—		402,607			62,130		—		(486		)	467,869
Other Costs
Miscellaneous Operating Expense	24,104			—		81			—		62,808		—			86,993
General and Administrative Costs	—			—		—			—		220		—			220
Depreciation, Depletion and Amortization	14			—		6			—		467		—			487
Loss on Debt Extinguishment	20,990			—		—			—		—		—			20,990
Interest Expense	52,908			2,629		(612		)	2,190		91		(1,809		)	55,397
Total Other Costs	98,016			2,629		(525		)	2,190		63,586		(1,809		)	164,087
Total Costs And Expenses	101,634			258,322		402,082			64,320		63,586		(2,295		)	887,649
(Loss) Earnings Before Income Tax	(39,346		)	37,686		43,433			11,825		4,320		(60,951		)	(3,033		)
Income Taxes	(37,701		)	13,281		21,399			—		1,633		—			(1,388		)
Net (Loss) Income	$	(1,645	)	$	24,405	$	22,034		$	11,825	$	2,687	$	(60,951	)	$	(1,645	)

Balance Sheet at December 31, 2014:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non-Guarantor		Other Subsidiary Non- Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	145,236		$	30,682		$	—		$	3	$	1,068		$	—		$	176,989
Accounts and Notes Receivable:
Trade	—			117,912			—			—		141,905			—			259,817
Other Receivables	25,497			309,247			29,937			384		12			(17,931		)	347,146
Inventories	—			14,748			76,486			10,639		—			—			101,873
Deferred Income Taxes	99,776			(33,207		)	—			—		—			—			66,569
Recoverable Income Taxes	79,426			(59,025		)	—			—		—			—			20,401
Prepaid Expenses	38,421			129,796			21,416			3,922		—			—			193,555
Total Current Assets	388,356			510,153			127,839			14,948		142,985			(17,931		)	1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	158,555			8,066,308			5,763,321			686,593		—			—			14,674,777
Less-Accumulated Depreciation, Depletion and Amortization	108,432			1,497,569			2,618,597			287,707		—			—			4,512,305
Total Property, Plant and Equipment-Net	50,123			6,568,739			3,144,724			398,886		—			—			10,162,472
Other Assets:
Investment in Affiliates	12,571,886			121,721			27,544			—		—			(12,568,193		)	152,958
Notes Receivable	—			—			160,831			—		—			(160,831		)	—
Other	172,884			71,339			28,550			4,977		—			—			277,750
Total Other Assets	12,744,770			193,060			216,925			4,977		—			(12,729,024		)	430,708
Total Assets	$	13,183,249		$	7,271,952		$	3,489,488		$	418,811	$	142,985		$	(12,746,955	)	$	11,759,530
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	86,313		$	385,381		$	44,497		$	15,782	$	—		$	—		$	531,973
Accounts Payable (Recoverable)-Related Parties	4,499,174			182,758			(5,333,209		)	—		(68,873		)	720,150			—
Current Portion of Long-Term Debt	2,485			6,602			3,599			18,261		—			(17,931		)	13,016
Short-Term Notes Payable	—			720,150			—			—		—			(720,150		)	—
Other Accrued Liabilities	119,484			172,787			275,199			35,502		—			—			602,972
Total Current Liabilities	4,707,456			1,467,678			(5,009,914		)	69,545		(68,873		)	(17,931		)	1,147,961
Long-Term Debt:	3,124,129			37,342			114,078			161,160		—			(160,831		)	3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(148,925		)	474,517			—			—		—			—			325,592
Postretirement Benefits Other Than Pensions	—			—			698,401			5,279		—			—			703,680
Pneumoconiosis Benefits	—			—			115,691			1,250		—			—			116,941
Mine Closing	—			—			299,663			7,126		—			—			306,789
Gas Well Closing	—			116,930			57,604			835		—			—			175,369
Workers’ Compensation	—			—			73,566			2,381		—			—			75,947
Salary Retirement	109,956			—			—			—		—			—			109,956
Reclamation	—			—			33,788			—		—			—			33,788
Other	61,175			94,378			2,009			609		—			—			158,171
Total Deferred Credits and Other Liabilities	22,206			685,825			1,280,722			17,480		—			—			2,006,233
Total CONSOL Energy Inc. Stockholders’ Equity	5,329,458			5,081,107			7,104,602			170,626		211,858			(12,568,193		)	5,329,458
Total Liabilities and Equity	$	13,183,249		$	7,271,952		$	3,489,488		$	418,811	$	142,985		$	(12,746,955	)	$	11,759,530

Income Statement for the Nine Months Ended September 30, 2015 (unaudited)



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors		CNXC Non- Guarantor		Other Subsidiary Non- Guarantors		Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	659,692		$	—	$	—	$	—	$	(1,194	)	$	658,498
Unrealized Gain (Loss) on Commodity Derivative Instruments	—			134,205			—		—		—		—			134,205
Coal Sales	—			—			1,109,427		205,321		—		—			1,314,748
Other Outside Sales	—			—			24,596		—		—		—			24,596
Production Royalty Interests and Purchased Gas Sales	—			39,423			—		—		—		—			39,423
Freight-Outside Coal	—			—			12,738		1,257		—		—			13,995
Miscellaneous Other Income	(246,791		)	46,625			65,510		615		4,105		242,336			112,400
Gain (Loss) on Sale of Assets	—			3,076			51,492		36		—		—			54,604
Total Revenue and Other Income	(246,791		)	883,021			1,263,763		207,229		4,105		241,142			2,352,469
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			83,385			—		—		—		—			83,385
Transportation, Gathering and Compression	—			258,329			—		—		—		—			258,329
Production, Ad Valorem, and Other Fees	—			24,605			—		—		—		—			24,605
Direct Administrative and Selling	—			38,630			—		—		—		—			38,630
Depreciation, Depletion and Amortization	—			262,356			—		—		—		—			262,356
Exploration and Production Related Other Costs	—			7,694			—		—		9		(9		)	7,694
Production Royalty Interests and Purchased Gas Costs	—			30,751			—		—		—		—			30,751
Other Corporate Expenses	—			66,633			—		—		—		—			66,633
Impairment of Exploration and Production Properties	—			828,905			—		—		—		—			828,905
General and Administrative	—			42,086			—		—		—		—			42,086
Total Exploration and Production Costs	—			1,643,374			—		—		9		(9		)	1,643,374
Coal Costs
Operating and Other Costs	5,568			—			639,888		111,783		—		(1,194		)	756,045
Royalties and Production Taxes	—			—			55,178		8,296		—		—			63,474
Direct Administrative and Selling	—			—			22,344		3,848		—		—			26,192
Depreciation, Depletion and Amortization	447			—			168,564		26,696		—		—			195,707
Freight Expense	—			—			12,738		1,257		—		—			13,995
General and Administrative Costs	—			—			15,024		6,762		—		—			21,786
Other Corporate Expenses	—			—			32,863		—		—		—			32,863
Total Coal Costs	6,015			—			946,599		158,642		—		(1,194		)	1,110,062
Other Costs
Miscellaneous Operating Expense	37,775			—			997		—		496		—			39,268
Depreciation, Depletion and Amortization	2			—			15		—		—		—			17
Loss on Debt Extinguishment	67,751			—			—		—		—		—			67,751
Interest Expense	141,493			4,840			4,776		6,597		76		(7,595		)	150,187
Total Other Costs	247,021			4,840			5,788		6,597		572		(7,595		)	257,223
Total Costs And Expenses	253,036			1,648,214			952,387		165,239		581		(8,798		)	3,010,659
(Loss) Earnings Before Income Tax	(499,827		)	(765,193		)	311,376		41,990		3,524		249,940			(658,190		)
Income Taxes	(94,536		)	(286,335		)	120,149		—		1,333		—			(259,389		)
Net (Loss) Income	(405,291		)	(478,858		)	191,227		41,990		2,191		249,940			(398,801		)
Less: Net Income Attributable to Noncontrolling Interest	—			—			—		—		—		6,490			6,490
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(405,291	)	$	(478,858	)	$	191,227	$	41,990	$	2,191	$	243,450		$	(405,291	)

Income Statement for the Nine Months Ended September 30, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		CNXC Non- Guarantor		Other Subsidiary Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	755,337	$	—	$	—	$	—		$	(1,938	)	$	753,399
Coal Sales	—			—		1,309,606		245,333		—			—			1,554,939
Other Outside Sales	—			—		28,685		—		184,362			—			213,047
Production Royalty Interests and Purchased Gas Sales	—			68,773		—		—		—			—			68,773
Freight-Outside Coal	—			—		19,565		2,986		—			—			22,551
Miscellaneous Other Income	304,076			51,688		99,525		7,269		7,442			(304,185		)	165,815
Gain (Loss) on Sale of Assets	—			11,560		922		120		13			—			12,615
Total Revenue and Other Income	304,076			887,358		1,458,303		255,708		191,817			(306,123		)	2,791,139
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			85,622		—		—		—			—			85,622
Transportation, Gathering and Compression	—			179,813		—		—		—			—			179,813
Production, Ad Valorem, and Other Fees	—			28,817		—		—		—			—			28,817
Direct Administrative and Selling	—			39,216		—		—		—			—			39,216
Depreciation, Depletion and Amortization	—			225,766		—		—		—			—			225,766
Exploration and Production Related Other Costs	—			15,765		—		—		—			—			15,765
Production Royalty Interests and Purchased Gas Costs	—			58,531		—		—		—			(13		)	58,518
Other Corporate Expenses	—			60,876		—		—		—			—			60,876
General and Administrative	—			47,755		—		—		—			—			47,755
Total Exploration and Production Costs	—			742,161		—		—		—			(13		)	742,148
Coal Costs
Operating and Other Costs	20,060			—		884,421		130,544		—			(1,937		)	1,033,088
Royalties and Production Taxes	—			—		66,442		10,955		—			—			77,397
Direct Administrative and Selling	—			—		29,342		5,012		—			—			34,354
Depreciation, Depletion and Amortization	472			—		163,060		24,873		—			—			188,405
Freight Expense	—			—		19,565		2,986		—			—			22,551
General and Administrative Costs	—			—		24,410		9,595		—			—			34,005
Other Corporate Expenses	—			—		41,444		—		—			—			41,444
Total Coal Costs	20,532			—		1,228,684		183,965		—			(1,937		)	1,431,244
Other Costs
Miscellaneous Operating Expense	63,895			—		1,111		—		181,349			—			246,355
General and Administrative Costs	—			—		—		—		651			—			651
Depreciation, Depletion and Amortization	27			—		52		—		1,430			—			1,509
Loss on Debt Extinguishment	95,267			—		—		—		—			—			95,267
Interest Expense	162,729			6,593		411		4,709		185			(4,088		)	170,539
Total Other Costs	321,918			6,593		1,574		4,709		183,615			(4,088		)	514,321
Total Costs And Expenses	342,450			748,754		1,230,258		188,674		183,615			(6,038		)	2,687,713
Earnings (Loss) Before Income Tax	(38,374		)	138,604		228,045		67,034		8,202			(300,085		)	103,426
Income Taxes	(127,798		)	51,828		81,183		—		3,102			—			8,315
Income (Loss) From Continuing Operations	89,424			86,776		146,862		67,034		5,100			(300,085		)	95,111
Loss From Discontinued Operations, net	—			—		—		—		(5,687		)	—			(5,687		)
Net Income (Loss)	$	89,424		$	86,776	$	146,862	$	67,034	$	(587	)	$	(300,085	)	$	89,424

Cash Flow for the Nine Months Ended September 30, 2015 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non-Guarantor			Other Subsidiary Non-Guarantors			Elimination			Consolidated
Net Cash (Used in) Provided by Operating Activities	$	(130,724	)	$	712,504		$	(289,359	)	$	47,034		$	(112	)	$	64,940		$	404,283
Cash Flows from Investing Activities:
Capital Expenditures	$	(8,607	)	$	(749,015	)	$	(116,946	)	$	(20,588	)	$	—		$	—		$	(895,156	)
Proceeds From Sales of Assets	47			3,600			79,341			56			—			—			83,044
(Investments in), net of Distributions from, Equity Affiliates	—			(62,860		)	(7,364		)	—			—			—			(70,224		)
Net Cash (Used in) Provided by Investing Activities	$	(8,560	)	$	(808,275	)	$	(44,969	)	$	(20,532	)	$	—		$	—		$	(882,336	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	945,000		$	70,000		$	—		$	—		$	—		$	(70,000	)	$	945,000
(Payments on) Proceeds from Miscellaneous Borrowings	(6,853		)	(4,823		)	5,310			4,804			—			—			(1,562		)
Payments on Long-Term Borrowings	(1,263,719		)	—			—			—			—			—			(1,263,719		)
Proceeds from Revolver - MLP	—			—			200,000			180,000			—			(200,000		)	180,000
Proceeds from Sale of MLP Interest	—			—			148,359			148,359			—			(148,359		)	148,359
Proceeds from Long-Term Borrowings	492,760			—			—			—			—			—			492,760
Net Distributions from Offering to Parent	—			—			—			(342,711		)	—			342,711			—
Net Change in Parent Advancements	—			—			—			(9,624		)	—			9,624			—
Tax Benefit from Stock-Based Compensation	208			—			—			—			—			—			208
Dividends Paid	(30,991		)	—			—			—			—			—			(30,991		)
Proceeds from Issuance of Common Stock	8,288			—			—			—			—			—			8,288
Treasury Stock Activity	(71,674		)	—			—			—			—			—			(71,674		)
Debt Issuance and Financing Fees	—			—			(19,341		)	(4,329		)	—			1,084			(22,586		)
Net Cash Provided by (Used in) Financing Activities	$	73,019		$	65,177		$	334,328		$	(23,501	)	$	—		$	(64,940	)	$	384,083

Cash Flow for the Nine Months Ended September 30, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non-Guarantor			Other Subsidiary Non- Guarantors			Elimination			Consolidated
Net Cash (Used in) Provided by Continuing Operations	$	(87,081	)	$	512,135		$	153,821		$	88,967		$	21,155		$	182,108		$	871,105
Net Cash Used In Discontinued Operating Activities	—			—			—			—			(20,934		)	—			(20,934		)
Net Cash (Used in) Provided by Operating Activities	$	(87,081	)	$	512,135		$	153,821		$	88,967		$	221		$	182,108		$	850,171
Cash Flows from Investing Activities:
Capital Expenditures	$	(2,314	)	$	(852,097	)	$	(262,896	)	$	(57,300	)	$	—		$	—		$	(1,174,607	)
Proceeds From Sales of Assets	(15,941		)	57,919			83,941			15,204			13			—			141,136
(Investments in), net of Distributions from, Equity Affiliates	—			79,723			28,809			—			—			—			108,532
Net Cash (Used in) Provided by Continuing Operations	$	(18,255	)	$	(714,455	)	$	(150,146	)	$	(42,096	)	$	13		$	—		$	(924,939	)
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	$	(11,736	)	$	233,663		$	—		—			$	—		$	(233,663	)	$	(11,736	)
(Payments on) Proceeds from Miscellaneous Borrowings	(662		)	—			(8,137		)	4,686			(56		)	—			(4,169		)
Payments on Long-Term Borrowings	(1,819,005		)	—			—			—			—			—			(1,819,005		)
Proceeds from Long-Term Borrowings	1,859,920			—			—			—			—			—			1,859,920
Net Change in Parent Advancements	—			—			—			(51,555		)	—			51,555			—
Tax Benefit from Stock-Based Compensation	2,478			—			—			—			—			—			2,478
Dividends Paid	(43,119		)	—			—			—			—			—			(43,119		)
Proceeds from Issuance of Common Stock	13,403			—			—			—			—			—			13,403
Debt Issuance and Financing Fees	(24,861		)	—			—			—			—			—			(24,861		)
Other Financing Activities	—			(4,460		)	4,460			—			—			—			—
Net Cash (Used in) Provided by Continuing Operations	$	(23,582	)	$	229,203		$	(3,677	)	$	(46,869	)	$	(56	)	$	(182,108	)	$	(27,089	)

Statement of Comprehensive Income for the Three Months Ended September 30, 2015 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non- Guarantor			Other Subsidiary Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	118,980		$	30,346		$	118,559		$	14,665		$	(142	)	$	(156,938	)	$	125,470
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	(49,353		)	—			(49,342		)	(12		)	—			49,354			(49,353		)
Reclassification of Cash Flow Hedge from OCI to Earnings	(20,602		)	(20,602		)	—			—			—			20,602			(20,602		)
Other Comprehensive (Loss) Income:	(69,955		)	(20,602		)	(49,342		)	(12		)	—			69,956			(69,955		)
Comprehensive Income (Loss)	49,025			9,744			69,217			14,653			(142		)	(86,982		)	55,515
Less: Comprehensive Income Attributable to Noncontrolling Interest	—			—			—			—			—			6,490			6,490
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	49,025		$	9,744		$	69,217		$	14,653		$	(142	)	$	(93,472	)	$	49,025

Statement of Comprehensive Income for the Three Months Ended September 30, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		CNXC Non- Guarantor			Other Subsidiary Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(1,645	)	$	24,405		$	22,034	$	11,825		$	2,687	$	(60,951	)	$	(1,645	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	184,154			—			184,512		(358		)	—		(184,154		)	184,154
Net Increase (Decrease) in the Value of Cash Flow Hedge	39,151			39,151			—		—			—		(39,151		)	39,151
Reclassification of Cash Flow Hedge from OCI to Earnings	(19,510		)	(19,510		)	—		—			—		19,510			(19,510		)
Other Comprehensive Income (Loss):	203,795			19,641			184,512		(358		)	—		(203,795		)	203,795
Comprehensive Income (Loss)	$	202,150		$	44,046		$	206,546	$	11,467		$	2,687	$	(264,746	)	$	202,150

Statement of Comprehensive Income for the Nine Months Ended September 30, 2015 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			CNXC Non- Guarantor			Other Subsidiary Non- Guarantors		Elimination		Consolidated
Net (Loss) Income	$	(405,291	)	$	(478,858	)	$	191,227		$	41,990		$	2,191	$	249,940	$	(398,801	)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	(40,036		)	—			(38,635		)	(1,401		)	—		40,036		(40,036		)
Reclassification of Cash Flow Hedge from OCI to Earnings	(60,720		)	(60,720		)	—			—			—		60,720		(60,720		)
Other Comprehensive (Loss) Income:	(100,756		)	(60,720		)	(38,635		)	(1,401		)	—		100,756		(100,756		)
Comprehensive (Loss) Income	(506,047		)	(539,578		)	152,592			40,589			2,191		350,696		(499,557		)
Less: Comprehensive Income Attributable to Noncontrolling Interest	—			—			—			—			—		6,490		6,490
Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(506,047	)	$	(539,578	)	$	152,592		$	40,589		$	2,191	$	344,206	$	(506,047	)

Statement of Comprehensive Income for the Nine Months Ended September 30, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		CNXC Non- Guarantor			Other Subsidiary Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	89,424		$	86,776		$	146,862	$	67,034		$	(587	)	$	(300,085	)	$	89,424
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	185,475			—			186,547		(1,072		)	—			(185,475		)	185,475
Net (Decrease) Increase in the Value of Cash Flow Hedge	(20,032		)	(20,032		)	—		—			—			20,032			(20,032		)
Reclassification of Cash Flow Hedge from OCI to Earnings	3,754			3,754			—		—			—			(3,754		)	3,754
Other Comprehensive Income (Loss):	169,197			(16,278		)	186,547		(1,072		)	—			(169,197		)	169,197
Comprehensive Income (Loss)	$	258,621		$	70,498		$	333,409	$	65,962		$	(587	)	$	(469,282	)	$	258,621

NOTE 17—RELATED PARTY TRANSACTIONS:

CONE Midstream Partners LP

On September 30, 2011, CNX Gas Company and Noble Energy, Inc., an unrelated third party and joint venture partner, formed CONE Gathering LLC (CONE) to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy accounts for CNX Gas Company's 50% ownership interest in CONE Gathering LLC under the equity method of accounting.

On September 30, 2014, CONE Midstream Partners, LP (the Partnership) closed its initial public offering of 20,125,000 common units representing limited partnership interests at a price to the public of $22.00 per unit, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters. The Partnership's general partner is CONE Midstream GP LLC, a wholly owned subsidiary of CONE Gathering LLC.

As a result of the IPO filing, the Partnership received net proceeds of $412,741 from the offering, after deducting underwriting discounts and commissions, and structuring fees of $28,779 along with additional estimated offering expenses of approximately $1,230. Of the proceeds received, $203,986 was distributed to both CNX Gas Company LLC ("CNX Gas Company") and Noble Energy on September 30, 2014.

During the nine months ended September 30, 2015, there were $8,541 of additional capital contributions to CONE Gathering, LLC and $58,212 to the Partnership. The capital contributions were offset, in part, by $12,364 of distributions from the Partnership. During the nine months ended September 30, 2014, there were $67,000 of additional capital contributions to CONE Gathering, LLC.

Following the CONE Midstream Partners IPO in September 2014, CONE Gathering LLC has a 2% general partner interest in the Partnership, while each sponsor has a 32.1% limited partner interest. CNX Gas Company accounts for its portion of the earnings in the Partnership under the equity method of accounting. At September 30, 2015, CNX Gas Company and Noble Energy each continue to own a 50% interest in the assets of CONE Gathering LLC that were not contributed to the Partnership. Equity in earnings of affiliates during the three months ended September 30, 2015 and 2014 related to CONE Gathering LLC was $6,423 and $9,615, respectively. Equity in earnings of affiliates related to CONE Midstream Partners, LP was $6,310 during the three months ended September 30, 2015. For the nine months ended September 30, 2015 and 2014, equity in earnings of affiliates related to CONE Gathering LLC was $14,099 and $20,839, respectively. For the nine months ended September 30, 2015, equity in earnings of affiliates related to CONE Midstream Partners, LP was $15,671.

During the nine months ended September 30, 2015 and 2014, CONE Gathering LLC (prior to September 30, 2014) and the Partnership (after September 30, 2014) provided gathering services to CNX Gas Company in the ordinary course of business. Gathering services received were $27,890 and $17,794 for the three months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015 and 2014, gathering services were $75,176 and $44,001, respectively. These costs were included in Exploration and Production Costs - Transportation, Gathering and Compression on CONSOL Energy’s accompanying Consolidated Statements of Income. At September 30, 2015 and December 31, 2014, CONSOL Energy had a net payable of $7,213 and $21,535 respectively, due to both the Partnership and CONE Gathering LLC primarily for accrued but unpaid gathering services. The net payable for both periods is included in Accounts Payable on CONSOL Energy’s accompanying Consolidated Balance Sheets.

During the three and nine months ended September 30, 2015, CONSOL Energy purchased no supply inventory and $2,239 of supply inventory from the Partnership, respectively.

CNX Coal Resources LP

On July 7, 2015, CNX Coal Resources LP (CNXC) closed its initial public offering of 5,000,000 common units representing limited partnership interests at a price to the public of $15.00 per unit. Additionally, Greenlight Capital entered into a common unit purchase agreement with CNXC pursuant to which Greenlight Capital agreed to purchase, and CNXC agreed to sell, 5,000,000 common units at a price per unit equal to $15.00, which equates to $75,000 in net proceeds. CNXC's general partner is CNX Coal Resources GP, a wholly owned subsidiary of CONSOL Energy. The underwriters of the IPO filing exercised an over-allotment option of 561,067 common units to the public at $15.00 per unit.

In connection with the IPO offering, CNXC entered into a $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent ("PNC"). Obligations under the revolving credit facility are guaranteed by certain of CNXC's subsidiaries (the "guarantor subsidiaries") and are secured by substantially all of CNXC's and

CNXC's subsidiaries' assets pursuant to a security agreement and various mortgages. In connection with the new revolving credit facility, CNXC made an initial draw of $200,000, and after origination fees of $3,000, the net proceeds were $197,000.

The total net proceeds related to these transactions that were distributed to CONSOL Energy were $342,711.

Charges for services from CONSOL Energy include the following:



	Three Months Ended				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2015		2014		2015		2014
Operating and Other Costs	$	1,680	$	1,337	$	3,468	$	3,784
Selling and Direct Administrative Expenses	1,034		1,411		3,297		4,530
General and Administrative Expenses	2,027		2,718		6,747		9,595
Total Services from CONSOL Energy	$	4,741	$	5,466	$	13,512	$	17,909

At September 30, 2015, CNXC had a net payable to CONSOL Energy in the amount of $1,188. This payable includes reimbursements for business expenses, executive fees, debt issuance and financing fees, stock-based compensation and other items.

NOTE 18—STOCK REPURCHASE:

In December 2014, CONSOL Energy's Board of Directors approved a stock repurchase program under which CONSOL Energy may purchase from time to time up to $250,000 of its common stock over the next two years. Under the terms of the program, CONSOL Energy may make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs or in structured share repurchase programs. Any repurchases of common stock will be funded from available cash on hand or short-term borrowings. The program does not obligate CONSOL Energy to acquire any particular amount of common stock, and it may be modified or suspended at any time at the Company's discretion. The program will be conducted in compliance with applicable legal requirements and within the limits imposed by any credit agreement, receivables purchase agreement or indenture and shall be subject to market conditions and other factors. During the three months ended September 30, 2015, no shares were repurchased. During the nine months ended September 30, 2015, 2,213,100 shares were repurchased and retired at an average price of $32.37 per share.

NOTE 19—RECENT ACCOUNTING PRONOUNCEMENTS:

In August 2015, the FASB issued update 2015-15 - Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting. This Accounting Standards Update adds SEC paragraphs pursuant to the SEC Staff Announcement at the June 18, 2015 Emerging Issues Task Force (EITF) meeting about the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements. As such, the update adds paragraphs 835-30-S35-1, 835-30-S45-1 and 835-30-S00-1 and their related headings to Subtopic 835-30. Together, the added paragraphs clarify that guidance in the FASB’s issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements (see paragraph 835-30-45-1A). As such, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

In August 2015, the FASB issued update 2015-14 - Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date. In response to stakeholders’ requests to defer the effective date of the guidance in Update 2014-09 - Revenue from Contracts with Customers (Topic 606), and in consideration of feedback received through extensive outreach with preparers, practitioners, and users of financial statements, the Board issued proposed Accounting Standards Update, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. Respondents to the proposed Update overwhelmingly support a deferral and noted that providing sufficient time for implementation of the guidance in Update 2014-09 is critical to its success. As such, the Board is issuing this Update in consideration of respondents’ feedback, including the timing of when Update 2014-09 was issued, the current status of key standard-setting activities associated with the guidance in Update 2014-09, and the availability of information technology solutions to facilitate the implementation of the guidance in

Update 2014-09. The amendments in this Update defer the effective date of Update 2014-09 for all entities by one year. Public business entities, certain not-for-profit entities, and certain employee benefit plans should apply the guidance in Update 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

In July 2015, the FASB issued update 2015-11 - Inventory (Topic 330): Simplifying the Measurement of Inventory. The Board is issuing this Update as part of its Simplification Initiative. The amendments in this Update do not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first-out (FIFO) or average cost. Topic 330, Inventory, currently requires an entity to measure inventory at the lower of cost or market, where market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. In accordance with this Update, an entity should now measure inventory within the scope of this Update at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. Other than the change in the subsequent measurement guidance from the lower of cost or market to the lower of cost and net realizable value for inventory within the scope of this Update, there are no other substantive changes to the guidance on measurement of inventory. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this Update should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

In May 2015, the FASB issued updated 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). The objective of this update is to address the diversity of the practice related to how certain investments measured at net asset value with redemption dates in the future (including periodic redemption dates) are categorized within the fair value hierarchy. Currently, investments valued using the practical expedient are categorized within the fair value hierarchy on the basis of whether the investment is redeemable with the investee at net asset value, or redeemable with the investee at net asset value at a future date. For investments that are redeemable with the investee at a future date, a reporting entity must take into account the length of time until those investments become redeemable to determine the classification within the fair value hierarchy. The amendments in this update remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using that practical expedient. A reporting entity should continue to disclose information on investments for which fair value is measured at net asset value (or its equivalent) as a practical expedient to help users understand the nature and risks of the investments and whether the investments, if sold, are probable of being sold at amounts different from net asset value. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

In April 2015, the FASB issued update 2015-04 - Compensation-Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer's Defined Benefit Obligation and Plan Assets. This update is part of the FASB's initiative to reduce complexity in accounting standards (the Simplification Initiative). If a contribution or significant event (such as a plan amendment, settlement, or curtailment that calls for a remeasurement in accordance with existing requirements) occurs between the month-end date used to measure defined benefit plan assets and obligations and an entity's fiscal year-end, the entity should adjust the measurement of defined benefit plan assets and obligations to reflect the effects of those contributions or significant events. However, an entity should not adjust the measurement of defined benefit plan assets and obligations for other events that occur between the month-end measurement and the entity's fiscal year-end that are not caused by the entity (for example, changes in market prices or interest rates). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations (for example, a partial settlement), the amendments in this update also provide a practical expedient that permits the entity to remeasure defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this update. The amendments in this update are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier application is permitted and the Company has applied this update.

In April 2015, the FASB issued update 2015-03 - Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. This update is part of the FASB's initiative to reduce complexity in accounting standards (the Simplification Initiative). The Board received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discounts and premiums creates unnecessary complexity. Recognizing debt issuance costs as a deferred charge (that is, an asset) also is different from the guidance in International Financial Reporting Standards (IFRS), which requires that transaction costs be deducted from the carrying value of the financial liability and not recorded as separate assets. Additionally, the requirement to recognize debt issuance costs as deferred charges conflicts with the guidance in FASB Concepts Statement No. 6, Elements of Financial Statements, which states that debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowing, thereby increasing the effective interest rate. Concepts Statement 6 further states that debt issuance costs cannot be an asset because they provide no future economic benefit. To simplify the presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. For public business entities, the amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. Management believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

In February 2015, the Financial Accounting Standards Board (FASB) issued Update 2015-02 - Consolidation (Topic 810): Amendments to the Consolidation Analysis. The standard changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The Accounting Standards Update (ASU) will be effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in United States GAAP when it becomes effective. In July 2015, the FASB approved the deferral of the effective date of this ASU to annual reporting periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15, 2016. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

NOTE 20—SUBSEQUENT EVENTS:

In October 2015, CONSOL Energy sold to private entities various non-strategic assets, including lignite reserves in South Texas and surface acreage in Illinois, for total cash proceeds of approximately $9,500. The financial gain for this transaction was approximately $8,800.


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

General

CONSOL Energy's E&P Division achieved record production of 86.1 Bcfe, or an increase of 33% from the 64.9 Bcfe produced in the year-earlier quarter. CONSOL Energy is increasing its 2015 annual gas production guidance by 20-25 Bcfe to 325-330 Bcfe, and the Company expects approximately 20% annual gas production growth for 2016. The E&P Division's total unit costs declined during the quarter to $2.63 per Mcfe, compared to $3.12 per Mcfe during the year-earlier quarter. Due to continued efficiency improvements, reductions in service costs and consumables, and the optimization of support personnel through zero-based budgeting, the E&P Division expects further reductions to capital intensity and total unit costs through 2016.

For the third quarter of 2015, CONSOL Energy's average sales price for natural gas, natural gas liquids, oil, and condensate was $2.35 per Mcfe. CONSOL Energy's average price for natural gas was $1.86 per Mcf for the quarter and, including hedging, was $2.46 per Mcf. During the third quarter, CONSOL Energy produced NGL, oil, and condensate volumes of 12.1 Bcfe, or 14% of the Company's total gas equivalent volumes. These liquids volumes were nearly double those of the year-earlier quarter, which then comprised 10% of the Company's total gas equivalent volumes. The average realized price for all liquids for the third quarter of 2015 was $9.99 per barrel.

The Company currently has a total of 1.2 Bcf per day of available firm transportation capacity. This is composed of 0.9 Bcf per day of firm capacity on existing pipelines and an additional 0.3 Bcf per day of long-term firm sales with major customers having their own firm capacity. Additionally, CONSOL Energy has contracted volumes of approximately 0.6 Bcf per day on several pipeline projects that will be completed over the next several years. Even with the future expiration of certain transportation contracts, the Company's effective firm transportation capacity will increase to approximately 1.6 Bcf per day. The average demand cost for the existing firm capacity is approximately $0.28 per MMBtu. The average demand cost for the existing and committed firm capacity is approximately $0.33 per MMBtu.

In addition to firm transportation capacity, CONSOL Energy has developed a processing portfolio to support the projected volumes from its wet production areas. The Company has agreements in place to support the processing of approximately 0.4 Bcf per day of gross natural gas volumes.

In the third quarter of 2015, the Pennsylvania Operations sold 5.7 million tons, which exceeded previous quarter's guidance of 5.4-5.6 million tons. The current thermal coal market remains extremely challenged due to low natural gas prices, tepid economic growth, and regulatory uncertainty. Despite these challenges, during the third quarter, CONSOL Energy made substantial strategic and tactical progress through securing additional thermal coal commitments.

Strategically, CONSOL Energy’s Pennsylvania Operations increased its 2016 committed position to 18.9 million tons, or approximately 74% of the total estimated sales tons based on the midpoint of the guidance range. Also, CONSOL Energy's Pennsylvania Operations committed positions for 2017 and 2018 increased to approximately 45% and 41%, respectively. Cumulatively, these multi-year commitments allow the Pennsylvania Operations to efficiently operate at an expected five-day per week work schedule, which also provides economies of scale to lower unit costs. The structure of these multi-year commitments price coal in 2016 but also allow for higher prices in 2017, and beyond, when markets are expected to strengthen. Domestic thermal coal prices are in contango, which ties to a few contracts that have prices locked in for 2017 and 2018.

Tactically, continuing into the fourth quarter, CONSOL Energy is positioned to selectively capture additional power plants across the eastern U.S., as well as spot sales, both domestic and international. CONSOL Energy expects that these incremental sales will increase the 2016 committed sales position to over 90% by year-end. As CONSOL Energy continues to secure market share, and as overall U.S. coal demand declines, the Company expects the idling of coal mines across a number of basins. This supply response may allow CONSOL Energy to selectively layer-in additional incremental sales for 2016, and beyond.

Also the third quarter of 2015, CONSOL Energy sold 0.9 million tons of its Buchanan low-vol coal, which was in-line with previous quarter's guidance of 0.8-1.0 million tons. Despite the continued degradation across the domestic and international metallurgical markets, Buchanan’s low cost position allows it to compete in a challenging environment. Also during the quarter, CONSOL Energy contracted for 0.9 million additional tons for 2015 and expects to capture ongoing opportunities throughout the year. CONSOL Energy has been successful developing new markets both domestically and in the Atlantic Basin.

During the third quarter CONSOL Energy sold 0.6 million tons of Miller Creek coal, which is flat compared to the year-earlier quarter.

CONSOL Energy 2015 - 2016 Guidance

E&P DIVISION GUIDANCE

CONSOL Energy expects fourth quarter 2015 gas production to be approximately 92-97 Bcfe, which would result in annual 2015 production guidance between 325-330 Bcfe, or 39% growth compared to 2014 total production. CONSOL Energy expects 2016 annual gas production to grow by approximately 20%.

Total hedged natural gas production in the 2015 fourth quarter is 63.3 Bcf. The annual gas hedge position is shown in the table below:



	2015	2016
Total Yearly Production (Bcfe) / % growth	325-330	+20%
Volumes Hedged (Bcf), as of 10/09/15	173.5*	224.0

* Includes 2015 actual settlements of 110.1 Bcf.

CONSOL Energy’s hedged gas volumes include a combination of NYMEX financial hedges and index financial hedges (NYMEX plus basis). In addition, to protect the NYMEX hedge volumes from basis exposure, CONSOL Energy enters into basis-only financial hedges and physical sales with fixed basis at certain sales points. CONSOL Energy’s gas hedge position is shown in the table below.



	Q4 2015			2015			2016
Total NYMEX + Basis^* (Bcf)	43.1			123.6			182.9
Average Hedge Price ($/Mcf)	$	3.42		$	3.62		$	3.30

NYMEX Only Hedges Exposed to Basis (Bcf)	20.2			49.9			41.1
Average Hedge Price ($/Mcf)	$	3.50		$	3.75		$	3.58

Total % Volumes Hedged	67		%	53		%	57		%
Total % Volumes with NYMEX and Basis Hedged	46		%	38		%	47		%
Total % Volumes with NYMEX Only Hedges Exposed to Basis	21		%	15		%	11		%

* Includes physical sales with fixed basis in Q4 2015, 2015, and 2016 of 18.1 Bcf, 50.0 Bcf, and 43.8 Bcf, respectively.

Note: % of volumes hedged is based off of the midpoint of estimated total production guidance for each respective period.

During the third quarter of 2015, CONSOL Energy added 34 Bcf in gas NYMEX hedges for the second half of 2015 and an additional 114 Bcf of NYMEX hedges for 2016. In addition, to help mitigate basis exposure on NYMEX hedges, in the third quarter, CONSOL Energy added 15.7 Bcf and 676 Bcf of basis hedges for the second half of 2015 and full-year 2016, respectively. The basis hedges are primarily on in-basin interstate pipelines, while the Company limits hedging volumes on premium interstate pipelines.

COAL DIVISION GUIDANCE

For full year 2016, Pennsylvania Operations sales guidance is higher, compared to 2015, resulting from an increased committed position. CONSOL Energy expects Pennsylvania Operations total unit costs to increase slightly in the fourth quarter of 2015, compared to the third quarter. However, for full year 2015, CONSOL Energy continues to expect average total unit costs, including DD&A, to be between $40-$43 per ton.

In the Virginia Operations, CONSOL Energy continues to expect 2015 total unit costs to be between $50-$55 per ton.

In the Other Operations (Miller Creek), CONSOL Energy continues to expect 2015 total unit costs to be between $50-$55 per ton.

Also, CONSOL Energy expects maintenance of production capital expenditures of $5 per ton moving forward.

The following table describes the forecasted contracted position (in millions of tons) for the years ending December 31, 2015 and 2016 as of October 26, 2015:



	2015	2016
Est. Total Coal Sales	28.9 - 29.9	30.6 - 33.4
Committed	28.6	20.2
Estimated Price (committed tons)	$57.00 - $59.00	$50.00 - $55.00
Est. PA Operations Sales	23.0 - 23.5	25.0 - 27.0
Committed	22.7	18.9
Est. VA Operations Sales	3.9 - 4.2	3.7 - 4.2
Committed	3.8	0.6
Est. Other Sales	2.0 - 2.2	1.9 - 2.2
Committed	2.1	0.7

Note: Committed tons are tons that are both committed to be purchased and priced. Committed tons exclude collared tons and tons that are sold but not yet priced. There are no collared tons in 2015. Collared tons in 2016 are 0.4 million tons, with a ceiling of $62.00 per ton and a floor of $57.00 per ton. Contracts with certain customers permit the customer to carry a portion of their contracted tons into the following year and/or to take gas instead of coal. For purposes of this table, the estimated price of each committed contract includes the base price stated in the contract and an estimate of the future adjustments to the contracted base price as set forth in such contract. The adjustment mechanisms reflect (i) variances in the quality characteristics of coal delivered to the customer beyond threshold quality characteristics specified in the applicable sales contract, (ii) the actual calorific value of coal delivered to the customer, and/or (iii) changes in electric power prices in the markets in which our customers operate, as adjusted for any factors set forth in the applicable contract. Each customer contract is different and not all contracts contain adjustments described in the preceding sentence. The estimated prices set forth in the table above were based in part on certain assumptions made by management. With respect to clause (i) quality characteristics, we based our assumption on our average monthly estimated quality numbers generated with our production forecast, created using pre-mining geology and analytical work, to determine the likely penalties and premiums associated with each contract using the average mine quality for tons estimated to be shipped during the time period. With respect to clause (ii) actual calorific value, we based our assumption on our average monthly estimated quality numbers generated with our production forecast, created using pre-mining geology and analytical work, to determine the likely penalties and premiums associated with each contract using the average mine quality for tons estimated to be shipped during the time period. With respect to clause (iii), the electric power price-related adjustments, if any, result only in positive monthly adjustments to the contracted base price that we receive for our coal. These adjustments to contracted base prices were estimated using publicly available regional power generation information applicable to the markets in which our customers operate and other internally estimated information regarding contract specific factors that impact pricing. The key assumptions used for the estimated electric power price-related adjustments were derived using PJM Western Hub Day-Ahead Calendar Month (Peak and Off-Peak) prices adjusted using management's judgment and historical results. These derived assumptions were held constant in 2015 and 2016. While management considers the expectations and assumptions regarding estimated prices, including with respect to estimated electric power price-related adjustments, to be reasonable, they are inherently subject to business, economic, competitive, regulatory, and other risks and uncertainties, most of which are beyond our control.

Results of Operations - Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Net Income (Loss) Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $119 million, or earnings of $0.52 per diluted share, for the three months ended September 30, 2015, compared to a net loss attributable to CONSOL Energy shareholders of $2 million, or a loss of $0.01 per diluted share, for the three months ended September 30, 2014.

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Coal. The total E&P division includes Marcellus segment, Utica segment, coalbed methane (CBM) segment, and Other Gas segement. The coal division is made up of the Pennsylvania Operations segment, Virginia Operations segment and Other Coal segment.

The total E&P division contributed $50 million of earnings before income tax for the three months ended September 30, 2015 compared to $38 million of earnings before income tax for the three months ended September 30, 2014. Total E&P sales volumes were 86.1 Bcfe for the three months ended September 30, 2015 compared to 64.9 Bcfe for the three months ended September 30, 2014.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio:



	For the Three Months Ended September 30,
in thousands (unless noted)	2015		2014		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	9,598		5,330		4,268			80.1	%
Sales Volume (Mbbls)	1,600		888		712			80.2	%
Gross Price ($/Bbl)	$	4.80	$	36.00	$	(31.2	)	(86.7	)%
Gross Revenue	$	7,645	$	31,952	$	(24,307	)	(76.1	)%

Oil:
Sales Volume (MMcfe)	189		183		6			3.3	%
Sales Volume (Mbbls)	32		31		1			3.2	%
Gross Price ($/Bbl)	$	54.18	$	90.12	$	(35.94	)	(39.9	)%
Gross Revenue	$	1,706	$	2,750	$	(1,044	)	(38.0	)%

Condensate:
Sales Volume (MMcfe)	2,337		815		1,522			186.7	%
Sales Volume (Mbbls)	390		136		254			186.8	%
Gross Price ($/Bbl)	$	27.84	$	87.96	$	(60.12	)	(68.3	)%
Gross Revenue	$	10,836	$	11,950	$	(1,114	)	(9.3	)%

GAS
Sales Volume (MMcf)	73,952		58,585		15,367			26.2	%
Sales Price ($/Mcf)	$	1.86	$	3.24	$	(1.38	)	(42.6	)%
Hedging Impact ($/Mcf)	$	0.60	$	0.36	$	0.24		66.7	%
Gross Revenue including Hedging Impact	$	182,118	$	211,190	$	(29,072	)	(13.8	)%

The average sales price and average costs for all active E&P operations were as follows:



	For the Three Months Ended September 30,
	2015			2014		Variance			Percent Change
Average Sales Price (per Mcfe)	$	2.35		$	3.97	$	(1.62	)	(40.8	)%
Average Costs (per Mcfe)	2.63			3.12		0.49			15.7	%
Margin	$	(0.28	)	$	0.85	$	(1.13	)	(132.9	)%

Total E&P division Natural Gas, NGLs, and Oil outside sales revenues were $202 million for the three months ended September 30, 2015 compared to $258 million for the three months ended September 30, 2014. The decrease was primarily due to the 40.8% decrease in average sales price per Mcfe, offset in part, by the 32.6% increase in total volumes sold. The decrease in average sales price is the result of a decrease in general market prices. The decrease was offset, in part, by our hedging program. These economic hedges represented approximately 48.1 Bcf of our produced gas sales volumes for the three months ended September 30, 2015 at an average gain of $0.92 per Mcf. These economic hedges represented approximately 41.7 Bcf of our produced gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.51 per Mcf.

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


•	The improvement in unit costs is primarily due to the 32.6% increase in total volumes sold in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 52.2% of natural gas and liquid sales volumes for the three months ended September 30, 2015 compared to 47.3% for the three months ended September 30, 2014.

•

Depreciation, depletion and amortization decreased on a unit basis primarily due to the adjustment to our shallow oil and gas rates after the impairment in the carrying value that was recognized in the second quarter of 2015, as well as the increase in sales volumes from our lower cost Marcellus production. The decrease was offset, in part, by an increase in total dollars as production continued to grow.


•	Lifting costs also decreased on a unit basis in the period-to-period comparison due to the increase in volumes sold and the ongoing cost reduction efforts of CONSOL's E&P operations team. The decrease in unit costs was partially offset by an increase in salt water disposal costs.


•	Direct administrative costs decreased on a unit basis primarily due to increase in gas sales volumes, as well as the recent Company reorganization.

The total coal division contributed $193 million of earnings before income tax for the three months ended September 30, 2015 compared to $54 million of earnings before income tax for the three months ended September 30, 2014. The total coal division sold 7.2 million tons of coal produced from CONSOL Energy mines for the three months ended September 30, 2015 compared to 7.8 million tons for the three months ended September 30, 2014.

The average sales price and average cost of goods sold per ton for continuing coal operations were as follows:



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Average Sales Price per ton sold	$	56.34	$	62.32	$	(5.98	)	(9.6	)%
Average Cost of Goods Sold per ton	43.39		49.93		6.54			13.1	%
Margin	$	12.95	$	12.39	$	0.56		4.5	%

The lower average sales price per ton sold reflects the continuing decrease in the global metallurgical and domestic thermal coal markets and the oversupply of coal used in steelmaking and electricity generation. The coal division priced 1.7 million tons on the export market for the three months ended September 30, 2015 compared to 1.3 million tons for the three months ended September 30, 2014. All other tons were sold on the domestic market.

The decrease in the average cost of goods sold per ton was primarily attributable to modifications made to the Pension and OPEB plans in September 2014 for active employees (refer to the discussion of total Company long-term liabilities for a detailed cost explanation). Also contributing to the decrease was improved longwall operations, better geological conditions, a reduced workforce, and other ongoing cost reduction efforts. In addition, PA Operations moved to a four-day work week in May 2015, compared to a normal five-day per week schedule, in order to preserve margins.

The Other division includes income taxes and other business activities not assigned to the E&P or Coal division.

General and Administrative (G&A) costs are allocated between divisions (E&P, Coal, Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. Upon execution of the CNX Coal Resources LP (CNXC) initial public offering (IPO), CNXC entered into a service arrangement with CONSOL Energy to provide certain general and administrative services. These services are paid monthly based on an agreed upon fixed fee that is reset annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

G&A costs are excluded from the E&P and Coal unit costs above. G&A costs were $20 million for the three months ended September 30, 2015 compared to $26 million for the three months ended September 30, 2014. G&A costs decreased due to the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Employee Wages and Related Expenses	$	8	$	11	$	(3	)	(27.3	)%
Consulting and Professional Services	6		7		(1		)	(14.3	)%
Contributions	1		2		(1		)	(50.0	)%
Advertising and Promotion	2		2		—			—	%
Miscellaneous	3		4		(1		)	(25.0	)%
Total Company General and Administrative Expense	$	20	$	26	$	(6	)	(23.1	)%


•	Employee Wages and Related Expenses decreased $3 million due to the Company reorganization that occurred in the three months ended September 30, 2015.


•	Consulting and professional services decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.


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


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


•	Miscellaneous items decreased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

Total Company long-term liabilities, such as OPEB, the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculated for the Company as a whole. In general, the expenses are then allocated to operational units based upon criteria specific to each liability. The allocation of OPEB and Pension expense in relation to the Coal Division has changed in 2015 to a methodology more in-line with the structural changes the Company has been making. The amounts are also no longer included in unit costs because the majority of the contributing employees are no longer active employees. Total CONSOL Energy expense related to our actuarial liabilities was income of $78 million for the three months ended September 30, 2015, compared to expense of $36 million for the three months ended September 30, 2014. The decrease of $114 million to total Company expense was primarily due to modifications made to the OPEB and Pension plans in September 2014, May 2015, and September 2015. See Note 16 - Pension and Other Postretirement Benefits Plans and Note 17 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Financial Statements in our December 31, 2014 Form 10-K and Note 4 - Components of Pension and OPEB Plans Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

TOTAL E&P DIVISION ANALYSIS for the three months ended September 30, 2015 compared to the three months ended September 30, 2014:

The E&P division had earnings before income tax of $50 million for the three months ended September 30, 2015 compared to earnings before income tax of $38 million in the three months ended September 30, 2014. Variances by individual E&P segment are discussed below.



	For the Three Months Ended												Difference to Three Months Ended
	September 30, 2015												September 30, 2014
(in millions)	Marcellus			Utica			CBM		Other Gas		Total E&P		Marcellus			Utica			CBM			Other Gas			Total E&P
Sales:
Produced	$	97		$	22		$	63	$	20	$	202	$	(13	)	$	(14	)	$	(20	)	$	(9	)	$	(56	)
Related Party	—			—			—		—		—		—			—			—			—			—
Total Outside Sales	97			22			63		20		202		(13		)	(14		)	(20		)	(9		)	(56		)
Unrealized Gain on Commodity Derivative Instruments	—			—			—		99		99		—			—			—			99			99
Production Royalty Interest	—			—			—		12		12		—			—			—			(6		)	(6		)
Purchased Gas	—			—			—		3		3		—			—			—			2			2
Miscellaneous Other Income	—			—			—		16		16		—			—			—			2			2
Gain on Sale of Assets	—			—			—		1		1		—			—			—			(4		)	(4		)
Total Revenue and Other Income	97			22			63		151		333		(13		)	(14		)	(20		)	84			37
Lifting	8			5			7		6		26		2			1			(2		)	(5		)	(4		)
Ad Valorem, Severance, and Other Taxes	5			1			2		—		8		—			1			(1		)	—			—
Transportation, Gathering and Compression	54			9			23		7		93		25			5			(4		)	(1		)	25
Direct Administrative and Selling	5			1			2		3		11		(4		)	—			(1		)	2			(3		)
Depreciation, Depletion and Amortization	43			17			20		10		90		9			10			(1		)	(10		)	8
General & Administration	—			—			—		13		13		—			—			—			(2		)	(2		)
Production Royalty Interest	—			—			—		9		9		—			—			—			(6		)	(6		)
Purchased Gas	—			—			—		2		2		—			—			—			1			1
Exploration and Other Costs	—			—			—		3		3		—			—			—			(5		)	(5		)
Other Corporate Expenses	—			—			—		27		27		—			—			—			13			13
Total Exploration and Production Costs	115			33			54		80		282		32			17			(9		)	(13		)	27
Interest Expense	—			—			—		1		1		—			—			—			(2		)	(2		)
Total E&P Division Costs	115			33			54		81		283		32			17			(9		)	(15		)	25
(Loss) Earnings Before Income Tax	$	(18	)	$	(11	)	$	9	$	70	$	50	$	(45	)	$	(31	)	$	(11	)	$	99		$	12

MARCELLUS GAS SEGMENT

The Marcellus segment had a loss before income tax of $18 million for the three months ended September 30, 2015 compared to earnings before income tax of $27 million for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
	2015			2014		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	38.1			27.0		11.1			41.1	%
NGLs Sales Volumes (Bcfe)*	5.5			3.3		2.2			66.7	%
Condensate Sales Volumes (Bcfe)*	1.3			0.4		0.9			225.0	%
Total Marcellus Sales Volumes (Bcfe)*	44.9			30.7		14.2			46.3	%

Average Sales Price - Gas (Mcf)	$	1.59		$	2.83	$	(1.24	)	(43.8	)%
Derivative Impact - Gas (Mcf)	$	0.62		$	0.39	$	0.23		59.0	%
Average Sales Price - NGLs (Mcfe)*	$	0.97		$	5.34	$	(4.37	)	(81.8	)%
Average Sales Price - Condensate (Mcfe)*	$	5.68		$	14.52	$	(8.84	)	(60.9	)%

Total Average Marcellus sales (per Mcfe)	$	2.16		$	3.58	$	(1.42	)	(39.7	)%
Average Marcellus lifting costs (per Mcfe)	0.18			0.18		—			—	%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	0.11			0.15		(0.04		)	(26.7	)%
Average Marcellus transportation, gathering, and compression costs (per Mcfe)	1.21			0.95		0.26			27.4	%
Average Marcellus direct administrative and selling costs (per Mcfe)	0.12			0.30		(0.18		)	(60.0	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	0.95			1.11		(0.16		)	(14.4	)%
Total Average Marcellus costs (per Mcfe)	$	2.57		$	2.69	$	(0.12	)	(4.5	)%
Average Margin for Marcellus (per Mcfe)	$	(0.41	)	$	0.89	$	(1.30	)	(146.1	)%

* NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

The Marcellus segment outside sales revenues were $97 million for the three months ended September 30, 2015 compared to $110 million for the three months ended September 30, 2014. The $13 million decrease was primarily due to a 39.7% decrease in total average sales price in the period-to-period comparison, partially offset by a 46.3% increase in total volumes sold. The decrease in Marcellus total average sales price was primarily the result of the $1.24 per Mcf decrease in gas market prices, along with a $0.37 per Mcfe decrease in the uplift from natural gas liquids and condensate sales volumes also due to declining market prices. The decrease was offset, in part, by a $0.23 per Mcf increase resulting from various transactions from our hedging program. These economic hedges represented approximately 27.7 Bcf of our produced Marcellus gas sales volumes for the three months ended September 30, 2015 at an average gain of $0.85 per Mcf. For the three months ended September 30, 2014, these economic hedges represented approximately 19.0 Bcf at an average gain of $0.55 per Mcf. The increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program.

Total costs for the Marcellus segment were $115 million for the three months ended September 30, 2015 compared to $83 million for the three months ended September 30, 2014. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $8 million for the three months ended September 30, 2015 compared to $6 million for the three months ended September 30, 2014. The increase in total dollars was primarily due to an increase in salt water disposal costs. Unit costs remained consistent in the period-to-period comparison.

•Marcellus ad valorem, severance and other taxes were $5 million for the three months ended September 30, 2015 and 2014. The decrease in unit costs was due to the increase in volumes sold.

•Marcellus transportation, gathering, and compression costs were $54 million for the three months ended September 30, 2015 compared to $29 million for the three months ended September 30, 2014. The increase in total dollars primarily relates to an increase in CONE gathering fees due to the 41.1% increase in gas sales volumes (See Note 17 - Related Party Transactions of

the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), an increase in processing fees associated with natural gas liquids primarily due to the 66.7% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increase in unit costs was also due to the increase in total dollars and was offset, in part, by the increase in gas sales volumes.

•Marcellus direct administrative and selling costs were $5 million for the three months ended September 30, 2015 compared to $9 million for the three months ended September 30, 2014. Direct administrative and selling costs attributable to the total E&P division are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The decrease in total dollars was primarily due to the recent Company reorganization. Unit costs were also positively impacted by the increase in gas sales volumes.

•Depreciation, depletion and amortization costs were $43 million for the three months ended September 30, 2015 compared to $34 million for the three months ended September 30, 2014. These amounts included depreciation on a per unit basis of $0.94 per Mcf and $1.09 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were recorded on a straight-line basis.

UTICA GAS SEGMENT

The Utica segment had a loss before income tax of $11 million for the three months ended September 30, 2015 compared to earnings before income tax of $20 million for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
	2015			2014		Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	10.2			4.3		5.9			137.2	%
NGLs Sales Volumes (Bcfe)*	4.1			2.0		2.1			105.0	%
Condensate Sales Volumes (Bcfe)*	1.0			0.4		0.6			150.0	%
Total Utica Sales Volumes (Bcfe)*	15.3			6.7		8.6			128.4	%

Average Sales Price - Gas (Mcf)	$	1.48		$	3.27	$	(1.79	)	(54.7	)%
Derivative Impact - Gas (Mcf)	$	0.09		$	0.17	$	(0.08	)	(47.1	)%
Average Sales Price - NGLs (Mcfe)*	$	0.56		$	7.06	$	(6.50	)	(92.1	)%
Average Sales Price - Condensate (Mcfe)*	$	3.24		$	14.77	$	(11.53	)	(78.1	)%

Total Average Utica sales price (per Mcfe)	$	1.41		$	5.29	$	(3.88	)	(73.3	)%
Average Utica lifting costs (per Mcfe)	0.34			0.65		(0.31		)	(47.7	)%
Average Utica ad valorem, severance, and other taxes (per Mcfe)	0.04			0.06		(0.02		)	(33.3	)%
Average Utica transportation, gathering, and compression costs (per Mcfe)	0.62			0.53		0.09			17.0	%
Average Utica direct administrative and selling costs (per Mcfe)	0.10			0.14		(0.04		)	(28.6	)%
Average Utica depreciation, depletion and amortization costs (per Mcfe)	1.04			0.99		0.05			5.1	%
Total Average Utica costs (per Mcfe)	$	2.14		$	2.37	$	(0.23	)	(9.7	)%
Average Margin for Utica (per Mcfe)	$	(0.73	)	$	2.92	$	(3.65	)	(125.0	)%

*NGLs and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

Utica outside sales revenues were $22 million for the three months ended September 30, 2015 compared to $36 million for the three months ended September 30, 2014. The $14 million decrease was primarily due to the 73.3% decrease in the total average sales price, partially offset by the 128.4% increase in total volumes sold. The 8.6 Bcfe increase in total volumes sold was primarily due to additional wells coming on-line from our ongoing drilling program which is currently focused on Marcellus and Utica production. The decrease in Utica total average sales price was primarily the result of a $1.79 per Mcf decrease in average market prices, as well as a $2.05 decrease in the uplift from natural gas liquids and condensate. Various transactions within our hedging program resulted in a $0.08 per Mcf decrease in the total average sales price for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014. These economic hedges represented approximately 1.4 Bcf of our produced Utica gas sales volumes for the three months ended September 30, 2015 at an average gain of $0.66 per Mcf. For the

three months ended September 30, 2014, these economic hedges represented approximately 1.0 Bcf at an average gain of $0.68 per Mcf.

Total costs for the Utica segment were $33 million for the three months ended September 30, 2015 compared to $16 million for the three months ended September 30, 2014. The increase in total dollars and decrease in unit costs were all directly related to the 128.4% increase in total volumes sold, thus a per unit analysis of the Utica segment is not meaningful.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $9 million to the total Company earnings before income tax for the three months ended September 30, 2015 compared to $20 million of earnings before income tax for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	18.5		20.0		(1.5		)	(7.5	)%

Average Sales Price - Gas (Mcf)	$	2.65	$	3.79	$	(1.14	)	(30.1	)%
Derivative Impact - Gas (Mcf)	$	0.77	$	0.38	$	0.39		102.6	%

Total Average CBM sales price (per Mcf)	$	3.42	$	4.17	$	(0.75	)	(18.0	)%
Average CBM lifting costs (per Mcf)	0.39		0.46		(0.07		)	(15.2	)%
Average CBM ad valorem, severance, and other taxes (per Mcf)	0.12		0.13		(0.01		)	(7.7	)%
Average CBM transportation, gathering, and compression costs (per Mcfe)	1.22		1.36		(0.14		)	(10.3	)%
Average CBM direct administrative and selling costs (per Mcf)	0.11		0.13		(0.02		)	(15.4	)%
Average CBM depreciation, depletion and amortization costs (per Mcf)	1.10		1.10		—			—	%
Total Average CBM costs (per Mcf)	$	2.94	$	3.18	$	(0.24	)	(7.5	)%
Average Margin for CBM (per Mcf)	$	0.48	$	0.99	$	(0.51	)	(51.5	)%

CBM outside sales revenues were $63 million in the three months ended September 30, 2015 compared to $83 million for the three months ended September 30, 2014. The $20 million decrease was primarily due to the 18.0% decrease in the total average sales price per Mcf as well as a 7.5% decrease in total volumes sold. The decrease in volumes sold was primarily due to normal well declines without a corresponding offset of additional wells drilled since the Company's current focus is on Marcellus and Utica production. The CBM total average sales price decreased $0.75 per Mcf due to a $1.14 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $0.39 per Mcf increase due to various transactions from our hedging program. These economic hedges represented approximately 14.0 Bcf of our produced CBM gas sales volumes for the three months ended September 30, 2015 at an average gain of $1.02 per Mcf. For the three months ended September 30, 2014, these economic hedges represented approximately 17.8 Bcf at an average gain of $0.42 per Mcf.

Total costs for the CBM segment were $54 million for the three months ended September 30, 2015 compared to $63 million for the three months ended September 30, 2014. The decrease in total dollars and unit costs for the CBM segment were due to the following items:

•CBM lifting costs were $7 million for the three months ended September 30, 2015 compared to $9 million for the three months ended September 30, 2014. The decrease in total dollars was primarily related to a decrease in contractual services related to well tending and a decrease in repair and maintenance costs. The decrease in unit costs was due to the decrease in total dollars offset, in part, by the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $2 million for the three months ended September 30, 2015 compared to $3 million for the three months ended September 30, 2014. The decrease of $1 million was due to a decrease in severance tax expense resulting from the $1.14 decrease in average sales price. Unit costs were also positively impacted by the decrease in average sales price which was offset, in part, by the decrease in gas sales volumes.

•CBM transportation, gathering, and compression costs were $23 million for the three months ended September 30, 2015 compared to $27 million for the three months ended September 30, 2014. The decrease of $4 million is primarily due to a decrease

in pipeline repairs and a decrease in utilized firm transportation expense resulting from the decrease in sales volumes. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in gas sales volumes.

•CBM direct administrative and selling costs were $2 million for the three months ended September 30, 2015 compared to $3 million for the three months ended September 30, 2014. The decrease in total dollars was primarily due to a smaller portion of the total company expense being allocated to the CBM segment along with the recent Company reorganization. Unit costs were also positively impacted by the decrease in total dollars which was offset, in part, by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $20 million for the three months ended September 30, 2015 compared to $21 million for the three months ended September 30, 2014. These amounts included depreciation on a per unit basis of $0.73 per Mcf and $0.74 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were recorded on a straight-line basis.

OTHER GAS SEGMENT

The Other Gas segment had earnings before income tax of $70 million for the three months ended September 30, 2015 compared to a loss before income tax of $29 million for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
	2015			2014			Variance			Percent Change
Other Gas Sales Volumes (Bcf)	7.2			7.3			(0.1		)	(1.4	)%
Oil Sales Volumes (Bcfe)*	0.2			0.2			—			—	%
Total Other Sales Volumes (Bcfe)*	7.4			7.5			(0.1		)	(1.3	)%

Average Sales Price - Gas (Mcf)	$	1.81		$	3.23		$	(1.42	)	(44.0	)%
Derivative Impact - Gas (Mcf)	$	0.81		$	0.36		$	0.45		125.0	%
Average Sales Price - Oil (Mcfe)*	$	9.25		$	15.17		$	(5.92	)	(39.0	)%

Total Average Other sales price (per Mcfe)	$	2.79		$	3.85		$	(1.06	)	(27.5	)%
Average Other lifting costs (per Mcfe)	0.83			1.47			(0.64		)	(43.5	)%
Average Other ad valorem, severance, and other taxes (per Mcfe)	0.12			0.11			0.01			9.1	%
Average Other transportation, gathering, and compression costs (per Mcfe)	0.86			1.09			(0.23		)	(21.1	)%
Average Other direct administrative and selling costs (per Mcfe)	0.26			0.17			0.09			52.9	%
Average Other depreciation, depletion and amortization costs (per Mcfe)	1.21			2.55			(1.34		)	(52.5	)%
Total Average Other costs (per Mcfe)	$	3.28		$	5.39		$	(2.11	)	(39.1	)%
Average Margin for Other (per Mcfe)	$	(0.49	)	$	(1.54	)	$	1.05		68.2	%

*Oil is converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, production royalty interest activity, unrealized gain on commodity derivative instruments, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific E&P segment.

Other gas sales volumes are primarily related to shallow oil and gas production as well as Upper Devonian Shale in Pennsylvania and West Virginia. Outside sales revenue from the Other Gas segment was approximately $20 million for the three months ended September 30, 2015 compared to $29 million for the three months ended September 30, 2014. The decrease in outside sales revenue primarily relates to the $1.06 decrease in total average sales price. Total costs related to these other sales were $26 million for the three months ended September 30, 2015 compared to $40 million for the three months ended September 30, 2014.

Unrealized gain on commodity derivative instruments represents changes in the fair value of all of the Company's existing gas commodity hedges on a mark-to-market basis. The unrealized gain on commodity derivative instruments of $99 million was

due to the December 31, 2014 de-designation of all derivative positions as cash flow hedges. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.

Production royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P division. Production royalty interest gas sales revenues were $12 million for the three months ended September 30, 2015 compared to $18 million for the three months ended September 30, 2014. 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 decrease.



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	5.9		5.5		0.4			7.3	%
Average Sales Price Per thousand cubic feet	$	1.96	$	3.21	$	(1.25	)	(38.9	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $3 million for the three months ended September 30, 2015 compared to $1 million for the three months ended September 30, 2014. The increase of $2 million was primarily due to the increase in purchased gas sales volumes.



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	1.2		0.4		0.8			200.0	%
Average Sales Price Per thousand cubic feet	$	2.12	$	3.08	$	(0.96	)	(31.2	)%

Miscellaneous other income was $16 million for the three months ended September 30, 2015 compared to $14 million for the three months ended September 30, 2014. The $2 million increase was primarily due to the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Equity in Earnings of Affiliates	$	13	$	10	$	3		30.0	%
Gathering Revenue	2		4		(2		)	(50.0	)%
Other	1		—		1			100.0	%
Total Miscellaneous Other Income	$	16	$	14	$	2		14.3	%


•	Earnings from our equity affiliates increased $3 million primarily due to an increase in earnings from CONE Midstream Partners, LP. and CONE Gathering, LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.


•	Gathering revenue decreased by $2 million in the period-to-period comparison, primarily due to a decrease in revenue related to certain gathering arrangements.


•	The remaining $1 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.

Gain on sale of assets was $1 million for the three months ended September 30, 2015 compared to $5 million for the three months ended September 30, 2014. The $4 million decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative costs are allocated to the total E&P division based on percentage of total revenue and percentage of total projected capital expenditures. Total E&P division costs were $13 million for the three months ended September 30, 2015 compared to $15 million for the three months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Production royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P division. Royalty interest gas costs were $9 million for the three months ended September 30, 2015 compared to $15 million for the three months ended September 30, 2014. The changes in market prices,

contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	5.9		5.5		0.4			7.3	%
Average Cost Per thousand cubic feet sold	$	1.54	$	2.70	$	(1.16	)	(43.0	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $2 million for the three months ended September 30, 2015 and $1 million for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	1.2		0.4		0.8			200.0	%
Average Cost Per thousand cubic feet sold	$	1.61	$	2.42	$	(0.81	)	(33.5	)%

Exploration and other costs were $3 million for the three months ended September 30, 2015 compared to $8 million for the three months ended September 30, 2014. The $5 million decrease is due to the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Lease Expiration Costs	$	2	$	3	$	(1	)	(33.3	)%
Land Rentals	1		1		—			—	%
Other	—		4		(4		)	(100.0	)%
Total Exploration and Other Costs	$	3	$	8	$	(5	)	(62.5	)%


•	Lease expiration costs decreased by $1 million in the period-to-period comparison, primarily due to a decreased number of leases expiring in the three months ended September 30, 2015 as compared to the three months ended September 30, 2014.


•	Land rental costs remained consistent in the period-to-period comparison.


•	The remaining $4 million decrease related to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $27 million for the three months ended September 30, 2015 compared to $14 million for the three months ended September 30, 2014. The $13 million increase in the period-to-period comparison was made up of the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014			Variance			Percent Change
Idle Rig Fees	$	7	$	—		$	7		100.0	%
Litigation Settlements	1		(5		)	6			(120.0	)%
Severance Expense	3		—			3			100.0	%
Stock-Based Compensation	3		3			—			—	%
Short-Term Incentive Compensation	3		4			(1		)	(25.0	)%
Unutilized Firm Transportation and Processing Fees	8		9			(1		)	(11.1	)%
Other	2		3			(1		)	(33.3	)%
Total Other Corporate Expenses	$	27	$	14		$	13		92.9	%


•	Idle rig fees are fees related to the temporary idling of some of the Company's natural gas rigs for the three months ended September 30, 2015. There were no idle rig fees for the three months ended September 30, 2014.


•	Litigation settlements increased by $6 million in the period-to-period comparison due to various activities that occurred throughout both periods, none of which were individually material.


•	Severance expense was a result of the recent Company reorganization. There was no such expense in the 2014 period.


•	Stock-based compensation 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 production, safety, and compliance. Short-term incentive compensation expense was lower for the 2015 period compared to the 2014 period due to lower payouts.


•	Unutilized firm transportation costs represent pipeline transportation capacity that the E&P division has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. Unutilized firm transportation decreased $1 million in the period-to-period comparison due to an increase in the utilization of the capacity.


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

Interest expense related to the E&P division was $1 million for the three months ended September 30, 2015 compared to $3 million for the three months ended September 30, 2014. Interest expense was incurred by the Other Gas segment on interest allocated to the E&P division under CONSOL Energy's credit facility.

TOTAL COAL DIVISION ANALYSIS for the three months ended September 30, 2015 compared to the three months ended September 30, 2014:

The coal division contributed $193 million of earnings before income tax for the three months ended September 30, 2015 compared to $54 million for the three months ended September 30, 2014. Variances by the individual coal segments are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	September 30, 2015											September 30, 2014
(in millions)	Pennsylvania Operations			Virginia Operations			Other Coal		Total Coal			Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal
Sales:
Produced Coal	$	323		$	49		$	32	$	404		$	(57	)	$	(22	)	$	—		$	(79	)
Purchased Coal	—			—			—		—			—			—			(1		)	(1		)
Total Coal Sales	323			49			32		404			(57		)	(22		)	(1		)	(80		)
Other Outside Sales	—			—			5		5			—			—			(3		)	(3		)
Freight Revenue	1			—			2		3			1			—			—			1
Miscellaneous Other Income	1			—			20		21			1			—			(6		)	(5		)
Gain on Sale of Assets	—			—			47		47			—			—			45			45
Total Revenue and Other Income	325			49			106		480			(55		)	(22		)	35			(42		)
Cost of Coal Sold:
Operating Costs	170			38			26		234			(55		)	(7		)	(4		)	(66		)
Direct Administrative and Selling	6			1			1		8			(2		)	—			—			(2		)
Total Royalty/Production Taxes	13			3			3		19			(3		)	(1		)	—			(4		)
Depreciation, Depletion and Amortization	40			9			1		50			(2		)	(1		)	(1		)	(4		)
Total Cost of Coal Sold:	229			51			31		311			(62		)	(9		)	(5		)	(76		)
Other Costs and Expenses:
Other Costs	(49		)	(24		)	12		(61		)	(51		)	(26		)	(30		)	(107		)
Direct Administrative and Selling	—			—			—		—			—			—			(1		)	(1		)
Total Royalty/Production taxes	—			—			1		1			—			—			1			1
Depreciation, Depletion and Amortization	2			3			8		13			—			1			—			1
Total Other Costs and Expenses:	(47		)	(21		)	21		(47		)	(51		)	(25		)	(30		)	(106		)
General and Administrative Expense	3			1			3		7			(3		)	(1		)	1			(3		)
Other Corporate Expense	5			2			4		11			(2		)	—			3			1
Freight Expense	1			—			2		3			1			—			—			1
Total Coal Costs	191			33			61		285			(117		)	(35		)	(31		)	(183		)
Interest Expense	2			—			—		2			2			—			—			2
Total Coal Division Costs	193			33			61		287			(115		)	(35		)	(31		)	(181		)
Earnings (Loss) Before Income Taxes	$	132		$	16		$	45	$	193		$	60		$	13		$	66		$	139

PENNSYLVANIA (PA) OPERATIONS COAL SEGMENT

The PA Operations coal segment's principal activities consist of mining, preparation and marketing of thermal coal to power generators. The segment also includes general and administrative activities as well as various other activities assigned to the PA Operations coal segment but not allocated to each individual mine and, therefore, are not included in unit cost presentation. For the three months ended September 30, 2015 and 2014, the segment included the following mines: Bailey Mine, Enlow Fork Mine, and Harvey Mine, and the corresponding preparation plant facilities.

The PA Operations coal segment contributed $132 million to total Company earnings before income tax for the three months ended September 30, 2015 compared to $72 million of earnings before income tax for the three months ended September 30, 2014. The PA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended September 30,
	2015		2014		Variance			Percent Change
Company Produced PA Operations Tons Sold (in millions)	5.7		6.2		(0.5		)	(8.1	)%
Average Sales Price Per PA Operations Ton Sold	$	56.99	$	61.35	$	(4.36	)	(7.1	)%

Total Operating Costs Per Ton Sold	$	30.24	$	36.69	$	(6.45	)	(17.6	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.06		1.23		(0.17		)	(13.8	)%
Total Royalty/Production Taxes Per Ton Sold	2.20		2.53		(0.33		)	(13.0	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.88		6.61		0.27			4.1	%
Total Costs Per PA Operations Ton Sold	$	40.38	$	47.06	$	(6.68	)	(14.2	)%
Average Margin Per PA Operations Ton Sold	$	16.61	$	14.29	$	2.32		16.2	%

Coal Sales

PA Operations produced coal outside sales revenues were $323 million for the three months ended September 30, 2015 compared to $380 million for the three months ended September 30, 2014. The $57 million decrease was attributable to a 0.5 million decrease in tons sold and a $4.36 per ton lower average sales price. The lower sales volumes and average coal sales price per PA Operations ton sold in the 2015 period were primarily the result of the continued decline in domestic and global thermal coal markets.

Freight Revenue

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, primarily rail, used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $1 million for the three months ended September 30, 2015 compared to no fright revenue in the three months ended September 30, 2014. The $1 million increase in freight revenue was due to increased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

Miscellaneous other income increased $1 million in the period-to-period comparison due to various transactions that occurred throughout the current period, none of which were individually material.

Cost of Coal Sold

Cost of coal sold is comprised of operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The cost of coal sold per ton includes items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold for PA Operations was $229 million for the three months ended September 30, 2015, or $62 million lower than the $291 million for the three months ended September 30, 2014. Total costs per PA Operations ton sold were $40.38 per ton for the three months ended September 30, 2015 compared to $47.06 per ton for the three months ended September 30, 2014. The decrease in the cost of coal sold was driven by improved longwall operations, better geological conditions, a reduced workforce, and other ongoing cost reduction efforts. In order to preserve margins, PA Operations moved to a four-day work week in May 2015, compared to a normal five-day per week schedule. There was also a decrease in the unit costs as a result of the Pension and OPEB plan modifications for active employees in September 2014. Refer to the discussion of total Company long-term liabilities

contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Costs And Expenses

Other costs include various costs and expenses that are assigned to the PA Operations coal segment but not allocated to each individual mine, and therefore, are not included in unit costs. Other costs, including certain administrative expenses and depreciation, depletion, and amortization, decreased $51 million in the three months ended September 30, 2015 compared to the three months ended September 30, 2014. This decrease was primarily attributable to $53 million of income due to modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation. The remaining increase was due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and administrative costs are allocated to each coal segment based upon the level of operating activity of the segment's underlying business units. Upon execution of the CNXC IPO, CNXC entered into a service arrangement with CONSOL Energy to provide certain general and administrative services. These services are paid monthly based on an agreed upon fixed fee that is reset annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. The amount of general and administrative costs related to PA Operations was $3 million for the three months ended September 30, 2015 compared to $6 million for the three months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expense is comprised of expenses for stock based compensation and the short-term incentive compensation program. These expenses include costs that are directly related to each coal segment along with a portion of costs that are allocated to each segment based on a percent of total labor costs. For the three months ended September 30, 2015, other corporate expenses were $5 million, compared to $7 million for the three months ended September 30, 2014. The $2 million decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Freight Expense

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, 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. Freight expense was $1 million for the three months ended September 30, 2015. There was no freight expense in the three months ended September 30, 2014. The increase in the period-to-period comparison was due to increased shipments under contracts where CONSOL Energy contractually provides transportation services.

Interest Expense

Interest expense is comprised of interest on the CNXC revolving credit facility. Upon execution of the CNXC IPO on July 7, 2015, CNXC drew down an initial $200,000 on the credit facility and incurred interest expense for the three months ended September 30, 2015. No such expense was incurred for the three months ended September 30, 2014.

VIRGINIA (VA) OPERATIONS COAL SEGMENT

The VA Operations coal segment's principal activities consist of mining, preparation and marketing of low volatile metallurgical coal to metal and coke producers. The segment also includes general and administrative activities as well as various other activities assigned to the VA Operations coal segment but not allocated to each individual mine, and therefore, are not included in unit cost presentation. For the three months ended September 30, 2015 and 2014, the segment included the Buchanan Mine and the corresponding preparation plant facilities.

The VA Operations coal segment contributed $16 million to total Company earnings before income tax for the three months ended September 30, 2015, compared to $3 million of earnings before income tax for the three months ended September 30, 2014. The VA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended September 30,
	2015			2014		Variance			Percent Change
Company Produced VA Operations Tons Sold (in millions)	0.9			1.0		(0.1		)	(10.0	)%
Average Sales Price Per VA Operations Ton Sold	$	51.82		$	70.57	$	(18.75	)	(26.6	)%

Total Operating Costs Per Ton Sold	$	40.14		$	44.37	$	(4.23	)	(9.5	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.53			1.40		0.13			9.3	%
Total Royalty/Production Taxes Per Ton Sold	3.06			4.50		(1.44		)	(32.0	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	9.10			10.94		(1.84		)	(16.8	)%
Total Costs Per VA Operations Ton Sold	$	53.83		$	61.21	$	(7.38	)	(12.1	)%
Average Margin Per VA Operations Ton Sold	$	(2.01	)	$	9.36	$	(11.37	)	(121.5	)%

Coal Sales

VA Operations produced coal outside sales revenues were $49 million for the three months ended September 30, 2015 compared to $71 million for the three months ended September 30, 2014. The $22 million decrease was attributable to an $18.75 per ton lower average sales price. Average sales prices for VA Operations coal decreased in the period-to-period comparison due to the continued weakening in the global metallurgical coal market.

Cost of Coal Sold

Total cost of coal sold for VA Operations was $51 million for the three months ended September 30, 2015, or $9 million lower than the $60 million for the three months ended September 30, 2014. Total costs per VA Operations ton sold were $53.83 per ton in the three months ended September 30, 2015, compared to $61.21 per ton for the three months ended September 30, 2014. The decrease in total dollars and unit costs per VA Operations ton sold was primarily due to a decrease in the gallons of wastewater treated and the effect of the Pension and OPEB plan modifications for active employees in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information. The decrease was offset, in part, due to an increase in the number of degasifcation wells drilled.

Other Costs And Expenses

Other costs, including certain administrative expenses and depreciation, depletion, and amortization, decreased $25 million in the three months ended September 30, 2015 compared to the three months ended September 30, 2014. This decrease was primarily attributable to $27 million of income due to modifications made to the OPEB plan in May 2015. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information. The remaining $2 million change related to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and administrative costs allocated to the VA Operations coal segment were $1 million for the three months ended September 30, 2015, compared to $2 million for the three months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses remained consistent in the period-to-period comparison.

OTHER COAL SEGMENT

The Other coal segment primarily includes coal terminal operations, idle mine activities and purchased coal activities, as well as various other activities not assigned to either PA Operations or VA Operations. The Other coal segment also includes activities related to mining, preparation and marketing of thermal coal to power generators geographically separated from PA Operations. For the three months ended September 30, 2015 and 2014, the segment included the Miller Creek Complex.

The Other coal segment contributed $45 million to total Company earnings before income tax for the three months ended September 30, 2015, compared to a loss before income tax of $21 million for the three months ended September 30, 2014. The Other coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2015		2014			Variance			Percent Change
Company Produced Other Operations Tons Sold (in millions)	0.6		0.6			—			—	%
Average Sales Price Per Other Operations Ton Sold	$	57.36	$	58.27		$	(0.91	)	(1.6	)%

Total Operating Costs Per Ton Sold	$	47.30	$	51.98		$	(4.68	)	(9.0	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.22		1.13			0.09			8.0	%
Total Royalty/Production Taxes Per Ton Sold	4.96		5.02			(0.06		)	(1.2	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	3.01		3.15			(0.14		)	(4.4	)%
Total Costs Per Other Operations Ton Sold	$	56.49	$	61.28		$	(4.79	)	(7.8	)%
Average Margin Per Other Operations Ton Sold	$	0.87	$	(3.01	)	$	3.88		128.9	%

Coal Sales

Other produced coal outside sales revenues remained consistent in the period-to-period comparison.

Purchased coal sales consisted of revenues from coal purchased from third parties and sold directly to CONSOL Energy's customers. There were no purchased coal sales for the three months ended September 30, 2015. Purchased coal sales revenue totaled $1 million for the three months ended September 30, 2014. The decrease was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

Other Outside Sales Revenue

Other outside sales revenue consists of revenues from the Company's coal terminal operations. Coal terminal operations sales revenues were $5 million for the three months ended September 30, 2015 compared to $8 million for the three months ended September 30, 2014. The decrease of $3 million in the period-to-period comparison was primarily due to a decrease in thru-put volumes in the current quarter.

Freight Revenue

Freight revenue remained consistent in the period-to-period comparison.

Miscellaneous Other Income

Miscellaneous other income was $20 million for the three months ended September 30, 2015 compared to $26 million for the three months ended September 30, 2014. The change is due to the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014		Variance
Equity in Earnings of Affiliates	$	2	$	7	$	(5	)
Royalty Income	5		5		—
Rental Income	9		9		—
Right of Way Sales	3		2		1
Other	1		3		(2		)
Total Other Income	$	20	$	26	$	(6	)


•	Equity in earnings of affiliates decreased $5 million due to the sale of the Company's interest in two equity affiliates in October 2014.


•	Royalty income remained consistent in the period-to-period comparison.


•	Rental income remained consistent in the period-to-period comparison.


•	Right of way sales increased $1 million due to additional revenue earned from the sale of several right of ways during the three months ended September 30, 2015.


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

Gain on Sale of Assets

Gain on sale of assets increased $45 million in the period-to-period comparison, primarily due to the sale of the Company's 49% interest in Western Allegheny Energy. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

Cost of Coal Sold

Total cost of coal sold attributable to the Other coal segment was $31 million for the three months ended September 30, 2015, or $5 million lower than the $36 million for the three months ended September 30, 2014. Total costs per Other Operations ton sold were $56.49 per ton for the three months ended September 30, 2015, compared to $61.28 per ton for the three months ended September 30, 2014. The decrease in cost of coal sold was primarily the result of the Pension and OPEB plan modifications for active employees in September 2014.

Other Costs And Expenses

Other costs and expenses related to the Other coal segment were $21 million for the three months ended September 30, 2015, compared to $51 million for the three months ended September 30, 2014. The decrease of $30 million was due to the following items:



	For the Three Months Ended September 30,
	2015			2014		Variance
OPEB Plan Changes	$	(21	)	$	—	$	(21	)
Closed and Idle Mines	9			18		(9		)
Coal Terminal Operations	4			6		(2		)
Coal Reserve Holding Costs	1			2		(1		)
Purchased Coal	—			1		(1		)
UMWA OPEB Expense	12			13		(1		)
Depreciation, Depletion & Amortization	8			8		—
Other	8			3		5
Total Other Costs	$	21		$	51	$	(30	)


•	Income of $21 million related to OPEB plan changes was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information.

•

Closed and idle mine costs decreased $9 million for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. This was due to a $5 million decrease in asset retirement obligations expense, primarily related to a reduction of the asset retirement obligation at the Fola Mining Complex during the three months ended September 30, 2015. The decrease was also due to a $2 million reduction in property taxes. The remaining decrease was due to various items that occurred throughout both periods, none of which were individually material.


•	Coal terminal operations costs decreased $2 million due to decreased thru-put volumes in the current quarter.


•	Coal reserve holding costs decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Purchased coal costs decreased $1 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.


•	UMWA OPEB expense decreased $1 million primarily due to a decrease in interest costs.


•	Depreciation, depletion, and amortization remained consistent in the period-to-period comparison.


•	Other costs increased $5 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and administrative costs allocated to the Other coal segment were $3 million for the three months ended September 30, 2015, compared to $2 million for the three months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses were $4 million for the three months ended September 30, 2015, compared to $1 million for the three months ended September 30, 2014. The $3 million increase was due to various transactions that occurred throughout both periods, none of which were individually material.

Freight Expense

Freight expense remained consistent in the period-to-period comparison.

OTHER DIVISION ANALYSIS for the three months ended September 30, 2015 compared to the three months ended September 30, 2014:

The other division includes expenses from various other corporate activities that are not allocated to the E&P or coal divisions. The other division had a loss before income tax of $60 million for the three months ended September 30, 2015 compared to a loss before income tax of $94 million for the three months ended September 30, 2014. The other division also includes total Company income tax expense of $58 million for the three months ended September 30, 2015 compared to an income tax benefit of $1 million for the three months ended September 30, 2014.



	For the Three Months Ended September 30,
(in millions)	2015			2014			Variance			Percent Change
Sales—Outside	$	—		$	65		$	(65	)	(100.0	)%
Other Income	1			1			—			—	%
Total Revenue	1			66			(65		)	(98.5	)%
Miscellaneous Operating Expense	15			87			(72		)	(82.8	)%
Loss on Debt Extinguishment	—			21			(21		)	(100.0	)%
Interest Expense	46			52			(6		)	(11.5	)%
Total Other Costs	61			160			(99		)	(61.9	)%
Loss Before Income Tax	(60		)	(94		)	34			(36.2	)%
Income Tax	58			(1		)	59			(5,900.0	)%
Net Loss	$	(118	)	$	(93	)	$	(25	)	26.9	%

There were no outside sales revenues from the other division for the three months ended September 30, 2015 compared to $65 million for the three months ended September 30, 2014. The decrease of $65 million was primarily related to the divestiture of our industrial supplies subsidiary in December 2014.

Other income remained consistent in the period-to-period comparison.

Total other costs related to the other division were $61 million for the three months ended September 30, 2015 compared to $160 million for the three months ended September 30, 2014. Other costs decreased due to the following items:



	For the Three Months Ended September 30,
(in millions)	2015		2014		Variance
Industrial Supplies	$	—	$	63	$	(63	)
Loss on Debt Extinguishment	—		21		(21		)
Long-Term Liability Plan Changes	—		10		(10		)
Interest Expense	46		52		(6		)
Pension Settlement	3		5		(2		)
Bank Fees	4		4		—
Severance Payments	5		—		5
Other	3		5		(2		)
	$	61	$	160	$	(99	)


•	There were no Industrial Supplies costs in the three months ended September 30, 2015 compared to $63 million in the three months ended September 30, 2014. The decrease was due to the divestiture of our industrial supplies subsidiary in December 2014.


•	Loss on Debt Extinguishment of $21 million was recognized in the three months ended September 30, 2014 related to the early extinguishment of debt due to the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 107.5%. No such transaction occurred in the current period.


•	Long-Term Liability Plan Changes during the three months ended September 30, 2014 include $46 million of expense for cash payments made to active employees related to changes in the OPEB plan. This expense is partially offset by $36 million of income as a result of curtailment associated with amendments to the pension and OPEB plans adopted during the third quarter of 2014.

•

Interest expense decreased $6 million in the period-to-period comparison due to the partial payoff of the 2020 and 2021 bonds in March and April 2015 and the payoff of the 2017 bonds issued in April 2014 and the partial payoff of the 2020 bonds issued in August 2014. Also, contributing to the decrease in interest expense was lower rates on the 2023 bonds issued in March 2015 and 2022 bonds issued in April and August 2014. This decrease is offset, in part, by an increase in interest expense on borrowings from the revolver.


•	Pension settlement expense decreased $2 million in the period-to-period comparison. See Note 4 - Components of Pension and OPEB Plans Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense.


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


•	Severance payments were $5 million for the three months ended September 30, 2015 due to the Company reorganization in the current quarter.


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

Income Taxes:

The effective income tax rate was 31.7% for the three months ended September 30, 2015 compared to 45.8% for the three months ended September 30, 2014. The effective rates for the three months ended September 30, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. For the three months ended September 30, 2015, CONSOL Energy recognized certain tax benefits related to a prior-year tax provision. That resulted in an expense of $27 million related to decreased percentage depletion deductions, offset, in part, by $5 million of tax benefit due to changes in the deduction for certain stock-related compensation.

As a result of closing an IRS audit, CONSOL Energy was required to file amended state income tax returns. In the quarter ended September 30, 2014 the Company filed the required amended returns and realized a discrete state income tax charge of $0.35 million which was offset, in part, by a federal tax benefit of $0.12 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.

Upon changes in facts and circumstances, management may conclude that deferred tax assets for which no valuation allowance is currently recorded may not be realizable in future periods, resulting in a future charge to record a valuation allowance. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. Positive evidence considered includes financial and tax earnings generated over the past three years, future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence includes financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods. Existing valuation allowances are re-examined under the same standards of positive and negative evidence. If it is determined that it is more likely than not that a deferred tax asset will be realized, the appropriate amount of the valuation allowance, if any, is released. Deferred tax assets and liabilities are also re-measured to reflect changes in underlying tax rates due to law changes.



	For the Three Months Ended September 30,
(in millions)	2015			2014			Variance			Percent Change
Total Company Earnings Before Income Tax	$	184		$	(3	)	$	187		(6,233.3	)%
Income Tax Expense (Benefit)	$	58		$	(1	)	$	59		(5,900.0	)%
Effective Income Tax Rate	31.7		%	45.8		%	(14.1		)%

Results of Operations - Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Net (Loss) Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $405 million, or a loss of $1.77 per diluted share, for the nine months ended September 30, 2015, compared to net income attributable to CONSOL Energy shareholders of $89 million, or earnings of $0.39 per diluted share, for the nine months ended September 30, 2014.

CONSOL Energy consists of two principal business divisions: Exploration and Production (E&P) and Coal. The total E&P division includes Marcellus segment, Utica segment, coalbed methane (CBM) segment, and Other Gas segment. The coal division is made up of the Pennsylvania Operations segment, Virginia Operations segment and Other Coal segment.

The total E&P division contributed a loss before income tax of $765 million for the nine months ended September 30, 2015 compared to $139 million of earnings before income tax for the nine months ended September 30, 2014. Total E&P sales volumes were 233.2 Bcfe for the nine months ended September 30, 2015 compared to 165.2 Bcfe for the nine months ended September 30, 2014. Included in the net loss was a second quarter 2015 pre-tax loss of $829 million primarily related to an impairment in the carrying value of CONSOL Energy's shallow oil and natural gas assets largely due to the continuation of depressed NYMEX forward prices.

The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production and sales portfolio:



	For the Nine Months Ended September 30,
in thousands (unless noted)	2015		2014			Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	23,357		8,818			14,539			164.9	%
Sales Volume (Mbbls)	3,893		1,470			2,423			164.8	%
Gross Price ($/Bbl)	$	11.52	$	42.30		$	(30.78	)	(72.8	)%
Gross Revenue	$	44,838	$	62,148		$	(17,310	)	(27.9	)%

Oil:
Sales Volume (MMcfe)	495		510			(15		)	(2.9	)%
Sales Volume (Mbbls)	83		85			(2		)	(2.4	)%
Gross Price ($/Bbl)	$	49.68	$	91.92		$	(42.24	)	(46.0	)%
Gross Revenue	$	4,098	$	7,808		$	(3,710	)	(47.5	)%

Condensate:
Sales Volume (MMcfe)	5,497		1,591			3,906			245.5	%
Sales Volume (Mbbls)	916		265			651			245.7	%
Gross Price ($/Bbl)	$	26.94	$	86.76		$	(59.82	)	(68.9	)%
Gross Revenue	$	24,706	$	23,004		$	1,702		7.4	%

GAS
Sales Volume (MMcf)	203,834		154,267			49,567			32.1	%
Sales Price ($/Mcf)	$	2.30	$	4.30		$	(2.00	)	(50.0	)%
Hedging Impact ($/Mcf)	$	0.57	$	(0.01	)	$	0.58		(5,800.0	)%
Gross Revenue including Hedging Impact	$	586,050	$	662,376		$	(76,326	)	(11.5	)%

The average sales price and average costs for all active E&P operations were as follows:



	For the Nine Months Ended September 30,
	2015			2014		Variance			Percent Change
Average Sales Price (per Mcfe)	$	2.83		$	4.57	$	(1.74	)	(38.1	)%
Average Costs (per Mcfe)	2.85			3.37		0.52			15.4	%
Margin	$	(0.02	)	$	1.20	$	(1.22	)	(101.7	)%

Total E&P division Natural Gas, NGLs, and Oil outside sales revenues were $660 million for the nine months ended September 30, 2015 compared to $755 million for the nine months ended September 30, 2014. The decrease was primarily due to the 38.1% decrease in average sales price per Mcfe, offset in part, by the 41.2% increase in total volumes sold. The decrease in average sales price is the result of a decrease in general market prices. The decrease was offset, in part, by our hedging program. These economic hedges represented approximately 110.1 Bcf of our produced gas sales volumes for the nine months ended September 30, 2015 at an average gain of $1.06 per Mcf. These economic hedges represented approximately 118.2 Bcf of our produced gas sales volumes for the nine months ended September 30, 2014 at an average loss of $0.01 per Mcf.

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


•	The improvement in unit costs is primarily due to the 41.2% increase in total volumes sold in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 51.5% of natural gas and liquid sales volumes for the nine months ended September 30, 2015 compared to 45.5% in the nine months ended September 30, 2014.

•

Depreciation, depletion and amortization decreased on a unit basis primarily due to the adjustment to our shallow oil and gas rates after the impairment in the carrying value that was recognized in the second quarter of 2015, as well as the increase in sales volumes from our lower cost Marcellus and Utica production. The decrease was offset, in part, by an increase in total dollars as production continued to grow.


•	Lifting costs also decreased on a unit basis in the period-to-period comparison due to the increase in sales volumes. The decrease in unit costs was partially offset by an increase in repairs and maintenance, salt water disposal, and contractual services related to well tending.


•	Direct administrative costs decreased on a unit basis primarily due to the increase in gas sales volumes, as well as the recent Company reorganization.

The total coal division contributed $356 million of earnings before income tax for the nine months ended September 30, 2015 compared to $287 million of earnings before income tax for the nine months ended September 30, 2014. The total coal division sold 22.7 million tons of coal produced from CONSOL Energy mines for the nine months ended September 30, 2015 compared to 24.3 million tons for the nine months ended September 30, 2014.

The average sales price and average cost of goods sold per ton for continuing coal operations were as follows:



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Average Sales Price per ton sold	$	57.89	$	63.64	$	(5.75	)	(9.0	)%
Average Cost of Goods Sold per ton	44.11		47.54		3.43			7.2	%
Margin	$	13.78	$	16.10	$	(2.32	)	(14.4	)%

The lower average sales price per ton sold reflects the continuing decrease in the global metallurgical and domestic thermal coal markets and the oversupply of coal used in steelmaking and electricity generation. The coal division priced 6.5 million tons on the export market for the nine months ended September 30, 2015 compared to 4.7 million tons for the nine months ended September 30, 2014. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily attributable to the decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014 and employed other cost cutting measures due to depressed market conditions. PA Operations also decreased operating shifts by moving to a four-day work week in May 2015, compared to a normal five-day per week schedule, in order to preserve margins. Also contributing to the decrease was the effect of the Pension and OPEB plan modifications for active employees in September 2014 for active employees. Refer to the discussion of total Company long-term liabilities for more information.

The Other division includes income taxes and other business activities not assigned to the E&P or Coal divisions.

G&A costs are excluded from the E&P and Coal unit costs above. G&A costs were $64 million for the nine months ended September 30, 2015 compared to $82 million for the nine months ended September 30, 2014. G&A costs decreased due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Contributions	$	2	$	11	$	(9	)	(81.8	)%
Employee Wages and Related Expenses	30		33		(3		)	(9.1	)%
Advertising and Promotion	5		5		—			—	%
Consulting and Professional Services	16		20		(4		)	(20.0	)%
Miscellaneous	11		13		(2		)	(15.4	)%
Total Company General and Administrative Expense	$	64	$	82	$	(18	)	(22.0	)%

•

Contributions decreased $9 million primarily due to a charitable contribution of $6 million to the Boy Scouts of America during the nine months ended September 30, 2014. The remaining $3 million decrease is due to various transactions that occurred, none of which were individually material, including a general decrease in prepaid trade association dues during the nine months ended September 30, 2015.


•	Employee wages and related expenses decreased $3 million due to the Company reorganization that occurred in the nine months ended September 30, 2015.


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


•	Consulting and professional services decreased $4 million due to various transactions that occurred throughout both periods, none of which were individually material, including a general decrease in legal expenses during the nine months ended September 30, 2015.


•	Miscellaneous costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

Total Company long-term liabilities, such as Other Post-Employment Benefits (OPEB), the salary retirement plan, workers' compensation, Coal Workers' Pneumoconiosis (CWP), and long-term disability are actuarially calculated for the Company as a whole. In general, the expenses are then allocated to operational units based upon criteria specific to each liability. The allocation of OPEB and Pension expense in relation to the Coal Division has changed in 2015 to a methodology more in-line with the structural changes the company has been making. The amounts are also no longer included in unit costs because the majority of the contributing employees are no longer active employees. Total CONSOL Energy expense related to our actuarial liabilities was income of $83 million for the nine months ended September 30, 2015 compared to expense of $116 million for the nine months ended September 30, 2014. The decrease of $199 million to total Company expense was primarily due to modifications made to the OPEB and Pension plans in September 2014, May 2015, and September 2015 coupled with pension settlement expense of $21 million in the second quarter of 2014. See Note 16 - Pension and Other Postretirement Benefits Plans and Note 17 - CWP and Workers' Compensation in the Notes to the Audited Financial Statements in our December 31, 2014 Form 10-K and Note 4 - Components of Pension and OPEB Plans Net Periodic Benefit Costs of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

TOTAL E&P DIVISION ANALYSIS for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014:

The E&P division had a loss before income tax of $765 million for the nine months ended September 30, 2015 compared to earnings before income tax of $139 million for the nine months ended September 30, 2014. Variances by individual E&P segment are discussed below.



	For the Nine Months Ended													Difference to Nine Months Ended
	September 30, 2015													September 30, 2014
(in millions)	Marcellus		Utica			CBM		Other Gas			Total E&P			Marcellus			Utica			CBM			Other Gas			Total E&P
Sales:
Produced	$	332	$	58		$	204	$	65		$	659		$	(7	)	$	3		$	(55	)	$	(35	)	$	(94	)
Related Party	—		—			1		—			1			—			—			(1		)	—			(1		)
Total Outside Sales	332		58			205		65			660			(7		)	3			(56		)	(35		)	(95		)
Unrealized Gain on Commodity Derivative Instruments	—		—			—		134			134			—			—			—			134			134
Production Royalty Interest	—		—			—		32			32			—			—			—			(31		)	(31		)
Purchased Gas	—		—			—		8			8			—			—			—			2			2
Miscellaneous Other Income	—		—			—		46			46			—			—			—			(5		)	(5		)
Gain on Sale of Assets	—		—			—		3			3			—			—			—			(9		)	(9		)
Total Revenue and Other Income	332		58			205		288			883			(7		)	3			(56		)	56			(4		)
Lifting	23		15			25		20			83			4			4			(3		)	(8		)	(3		)
Ad Valorem, Severance, and Other Taxes	14		1			6		4			25			2			—			(3		)	(3		)	(4		)
Transportation, Gathering and Compression	142		23			72		21			258			71			18			(7		)	(4		)	78
Direct Administrative and Selling	21		5			7		6			39			(5		)	2			(1		)	4			—
Depreciation, Depletion and Amortization	115		37			62		48			262			25			27			(5		)	(9		)	38
General & Administration	—		—			—		42			42			—			—			—			(6		)	(6		)
Production Royalty Interest	—		—			—		25			25			—			—			—			(29		)	(29		)
Purchased Gas	—		—			—		6			6			—			—			—			1			1
Exploration and Other Costs	—		—			—		8			8			—			—			—			(7		)	(7		)
Other Corporate Expenses	—		—			—		895			895			—			—			—			834			834
Total Exploration and Production Costs	315		81			172		1,075			1,643			97			51			(19		)	773			902
Interest Expense	—		—			—		5			5			—			—			—			(2		)	(2		)
Total E&P Division Costs	315		81			172		1,080			1,648			97			51			(19		)	771			900
Earnings (Loss) Before Income Tax	$	17	$	(23	)	$	33	$	(792	)	$	(765	)	$	(104	)	$	(48	)	$	(37	)	$	(715	)	$	(904	)

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $17 million of earnings before income tax for the nine months ended September 30, 2015 compared to $121 million of earnings before income tax for the nine months ended September 30, 2014.



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	103.2		68.3		34.9			51.1	%
NGLs Sales Volumes (Bcfe)*	14.2		6.2		8.0			129.0	%
Condensate Sales Volumes (Bcfe)*	2.8		0.7		2.1			300.0	%
Total Marcellus Sales Volumes (Bcfe)*	120.2		75.2		45.0			59.8	%

Average Sales Price - Gas (Mcf)	$	2.22	$	4.16	$	(1.94	)	(46.6	)%
Derivative Impact - Gas (Mcf)	$	0.52	$	0.04	$	0.48		1,200.0	%
Average Sales Price - NGLs (Mcfe)*	$	2.42	$	6.93	$	(4.51	)	(65.1	)%
Average Sales Price - Condensate (Mcfe)*	$	5.40	$	13.72	$	(8.32	)	(60.6	)%

Total Average Marcellus sales (per Mcfe)	$	2.76	$	4.51	$	(1.75	)	(38.8	)%
Average Marcellus lifting costs (per Mcfe)	0.19		0.25		(0.06		)	(24.0	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	0.12		0.16		(0.04		)	(25.0	)%
Average Marcellus transportation, gathering, and compression costs (per Mcfe)	1.18		0.95		0.23			24.2	%
Average Marcellus direct administrative and selling costs (per Mcfe)	0.18		0.34		(0.16		)	(47.1	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	0.95		1.20		(0.25		)	(20.8	)%
Total Average Marcellus costs (per Mcfe)	$	2.62	$	2.90	$	(0.28	)	(9.7	)%
Average Margin for Marcellus (per Mcfe)	$	0.14	$	1.61	$	(1.47	)	(91.3	)%

The Marcellus segment outside sales revenues were $332 million for the nine months ended September 30, 2015 compared to $339 million for the nine months ended September 30, 2014. The $7 million decrease was primarily due to a 38.8% decrease in total average sales prices in the period-to-period comparison, offset in part by a 59.8% increase in total volumes sold. The increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program. The decrease in Marcellus total average sales price was primarily the result of the $1.94 per Mcf decrease in gas market prices, along with a $0.23 per Mcfe decrease in the uplift from natural gas liquids and condensate sales volumes also due to the decrease in market prices. The decrease was offset, in part, by a $0.48 per Mcf increase resulting from various transactions from our hedging program. These economic hedges represented approximately 54.3 Bcf of our produced Marcellus gas sales volumes for the nine months ended September 30, 2015 at an average gain of $0.99 per Mcf. For the nine months ended September 30, 2014, these economic hedges represented approximately 50.3 Bcf at an average gain of $0.05 per Mcf.

Total costs for the Marcellus segment were $315 million for the nine months ended September 30, 2015 compared to $218 million for the nine months ended September 30, 2014. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $23 million for the nine months ended September 30, 2015 compared to $19 million for the nine months ended September 30, 2014. The increase in total dollars was due to increased salt water disposal costs, increased repair and maintenance costs, and increased contractual services related to well tending. The decrease in unit costs was primarily due to the 59.8% increase in total sales volumes.

•Marcellus ad valorem, severance and other taxes were $14 million for the nine months ended September 30, 2015 compared to $12 million for the nine months ended September 30, 2014. The increase in total dollars was primarily due to an increase in severance tax expense caused by the increase in total sales volumes and the mix of volumes by state.

•Marcellus transportation, gathering, and compression costs were $142 million for the nine months ended September 30, 2015 compared to $71 million for the nine months ended September 30, 2014. The $71 million increase in total dollars primarily related to an increase in the CONE gathering fee due to the increase in gas sales volumes (See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), an increase in processing fees associated with natural gas liquids primarily due to the 129.0% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increase in unit costs was also due to the increase in total dollars and was offset, in part, by the increase in gas sales volumes.

•Marcellus direct administrative and selling costs were $21 million for the nine months ended September 30, 2015 compared to $26 million for the nine months ended September 30, 2014. Direct administrative and selling costs attributable to the total E&P division are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The decrease in total dollars was primarily due to the recent Company reorganization. Unit costs were positively impacted by the increase in gas sales volumes.

•Depreciation, depletion and amortization costs were $115 million for the nine months ended September 30, 2015 compared to $90 million for the nine months ended September 30, 2014. These amounts included depreciation on a per unit basis of $0.94 per Mcf and $1.18 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were recorded on a straight-line basis.

UTICA GAS SEGMENT

The Utica segment had a loss before income tax of $23 million for the nine months ended September 30, 2015 compared to earnings before income tax of $25 million for the nine months ended September 30, 2014.



	For the Nine Months Ended September 30,
	2015			2014		Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	23.6			6.1		17.5			286.9	%
NGLs Sales Volumes (Bcfe)*	9.1			2.7		6.4			237.0	%
Oil Sales Volumes (Bcfe)*	0.1			—		0.1			100.0	%
Condensate Sales Volumes (Bcfe)*	2.7			0.9		1.8			200.0	%
Total Utica Sales Volumes (Bcfe)*	35.5			9.7		25.8			266.0	%

Average Sales Price - Gas (Mcf)	$	1.54		$	3.74	$	(2.20	)	(58.8	)%
Derivative Impact - Gas (Mcf)	$	0.04		$	0.07	$	(0.03	)	(42.9	)%
Average Sales Price - NGLs (Mcfe)*	$	1.14		$	7.32	$	(6.18	)	(84.4	)%
Average Sales Price - Oil (Mcfe)*	$	6.69		$	17.59	$	(10.90	)	(62.0	)%
Average Sales Price - Condensate (Mcfe)*	$	3.59		$	15.06	$	(11.47	)	(76.2	)%

Total Average Utica sales price (per Mcfe)	$	1.63		$	5.81	$	(4.18	)	(71.9	)%
Average Utica lifting costs (per Mcfe)	0.41			1.12		(0.71		)	(63.4	)%
Average Utica ad valorem, severance, and other taxes (per Mcfe)	0.04			0.13		(0.09		)	(69.2	)%
Average Utica transportation, gathering, and compression costs (per Mcfe)	0.64			0.52		0.12			23.1	%
Average Utica direct administrative and selling costs (per Mcfe)	0.14			0.27		(0.13		)	(48.1	)%
Average Utica depreciation, depletion and amortization costs (per Mcfe)	1.05			1.19		(0.14		)	(11.8	)%
Total Average Utica costs (per Mcfe)	$	2.28		$	3.23	$	(0.95	)	(29.4	)%
Average Margin for Utica (per Mcfe)	$	(0.65	)	$	2.58	$	(3.23	)	(125.2	)%

*NGLs, Oil and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.

Utica outside sales revenues were $58 million for the nine months ended September 30, 2015 compared to $55 million for the nine months ended September 30, 2014. The increase was primarily due to the 266.0% increase in total volumes sold and was offset, in part, by the 71.9% decrease in the total average sales price. The 25.8 Bcfe increase in total volumes sold was primarily due to additional wells coming on-line from our ongoing drilling program which is currently focused on Marcellus and Utica production. The decrease in Utica total average sales price was primarily the result of a $4.18 per Mcf decrease in average market

prices, along with a $0.03 per Mcf decrease resulting from various transactions from our hedging program. These economic hedges represented approximately 1.4 Bcf of our produced Utica gas sales volumes for the nine months ended September 30, 2015 at an average gain of $0.66 per Mcf. For the nine months ended September 30, 2014, these economic hedges represented approximately 2.5 Bcf at an average gain of $0.18 per Mcf.

Total costs for the Utica segment were $81 million for the nine months ended September 30, 2015 compared to $30 million for the nine months ended September 30, 2014. The increase in total dollars and decrease in unit costs were all directly related to the 266.0% increase in total volumes sold, thus a per unit analysis of the Utica segment is not meaningful.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $33 million of earnings before income tax for the nine months ended September 30, 2015 compared to $70 million of earnings before income tax for the nine months ended September 30, 2014.



	For the Nine Months Ended September 30,
	2015		2014			Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	56.2		59.5			(3.3		)	(5.5	)%

Average Sales Price - Gas (Mcf)	$	2.81	$	4.47		$	(1.66	)	(37.1	)%
Derivative Impact - Gas (Mcf)	$	0.83	$	(0.07	)	$	0.90		1,285.7	%

Total Average CBM sales price (per Mcf)	$	3.64	$	4.40		$	(0.76	)	(17.3	)%
Average CBM lifting costs (per Mcf)	0.44		0.47			(0.03		)	(6.4	)%
Average CBM ad valorem, severance, and other taxes (per Mcf)	0.11		0.16			(0.05		)	(31.3	)%
Average CBM transportation, gathering, and compression costs (per Mcfe)	1.28		1.33			(0.05		)	(3.8	)%
Average CBM direct administrative and selling costs (per Mcf)	0.12		0.13			(0.01		)	(7.7	)%
Average CBM depreciation, depletion and amortization costs (per Mcf)	1.10		1.11			(0.01		)	(0.9	)%
Total Average CBM costs (per Mcf)	$	3.05	$	3.20		$	(0.15	)	(4.7	)%
Average Margin for CBM (per Mcf)	$	0.59	$	1.20		$	(0.61	)	(50.8	)%

CBM outside sales revenues were $205 million for the nine months ended September 30, 2015 compared to $261 million for the nine months ended September 30, 2014. The $56 million decrease was primarily due to a 17.3% decrease in the total average sales price per Mcf as well as a 5.5% decrease in total volumes sold. The decrease in volumes sold was primarily due to normal well declines without a corresponding offset of additional wells drilled since the Company's current focus is on Marcellus and Utica production. The CBM total average sales price decreased $0.76 per Mcf due to a $1.66 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $0.90 per Mcf increase due to various transactions from our hedging program. These economic hedges represented approximately 40.9 Bcf of our produced CBM gas sales volumes for the nine months ended September 30, 2015 at an average gain of $1.14 per Mcf. For the nine months ended September 30, 2014, these economic hedges represented approximately 53.0 Bcf at a loss of $0.08 per Mcf.

Total costs for the CBM segment were $172 million for the nine months ended September 30, 2015 compared to $191 million for the nine months ended September 30, 2014. The decrease in total dollars and unit costs for the CBM segment were due to the following items:

•CBM lifting costs were $25 million for the nine months ended September 30, 2015 compared to $28 million for the nine months ended September 30, 2014. The decrease in total dollars was primarily related to a decrease in contractual services related to well tending and a decrease in repairs and maintenance expense. The decrease in unit costs was due to the decrease in total dollars offset, in part, by the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $6 million for the nine months ended September 30, 2015 compared to $9 million for the nine months ended September 30, 2014. The decrease of $3 million was due to a decrease in severance tax expense resulting from the 17.3% decrease in average sales price. Unit costs were also positively impacted by the decrease in average sales price which was offset, in part, by the decrease in gas sales volumes.

•CBM transportation, gathering, and compression costs were $72 million for the nine months ended September 30, 2015 compared to $79 million for the nine months ended September 30, 2014. The $7 million decrease in total dollars was primarily related to a decrease in repairs and maintenance, power, and a decrease in utilized firm transportation expense resulting from the decrease in sales volumes. Unit costs were also positively impacted by the decrease in total dollars, which was offset, in part, by the decrease in sales volumes.

•CBM direct administrative and selling costs were $7 million for the nine months ended September 30, 2015 compared to $8 million for the nine months ended September 30, 2014. The decrease in total dollars is primarily due to a smaller portion of the total company expense being allocated to the CBM segment along with the recent Company reorganization. Unit costs also decreased in the period-to-period comparison, primarily as a result of the decrease in total dollars, offset, in part, by the decrease in sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $62 million for the nine months ended September 30, 2015 compared to $67 million for the nine months ended September 30, 2014. These amounts included depreciation on a per unit basis of $0.73 per Mcf and $0.75 per Mcf, respectively. The remaining depreciation, depletion and amortization costs were recorded on a straight-line basis.

OTHER GAS SEGMENT

The Other Gas segment had a loss before income tax of $792 million for the nine months ended September 30, 2015 compared to a loss before income tax of $77 million for the nine months ended September 30, 2014.



	For the Nine Months Ended September 30,
	2015			2014			Variance			Percent Change
Other Gas Sales Volumes (Bcf)	20.9			20.3			0.6			3.0	%
Oil Sales Volumes (Bcfe)*	0.4			0.5			(0.1		)	(20.0	)%
Total Other Sales Volumes (Bcfe)*	21.3			20.8			0.5			2.4	%

Average Sales Price - Gas (Mcf)	$	2.21		$	4.44		$	(2.23	)	(50.2	)%
Derivative Impact - Gas (Mcf)	$	0.73		$	0.01		$	0.72		7,200.0	%
Average Sales Price - Oil (Mcfe)*	$	8.49		$	15.22		$	(6.73	)	(44.2	)%

Total Average Other sales price (per Mcfe)	$	3.06		$	4.70		$	(1.64	)	(34.9	)%
Average Other lifting costs (per Mcfe)	0.98			1.33			(0.35		)	(26.3	)%
Average Other ad valorem, severance, and other taxes (per Mcfe)	0.16			0.32			(0.16		)	(50.0	)%
Average Other transportation, gathering, and compression costs (per Mcfe)	1.03			1.18			(0.15		)	(12.7	)%
Average Other direct administrative and selling costs (per Mcfe)	0.29			0.16			0.13			81.3	%
Average Other depreciation, depletion and amortization costs (per Mcfe)	2.06			2.61			(0.55		)	(21.1	)%
Total Average Other costs (per Mcfe)	$	4.52		$	5.60		$	(1.08	)	(19.3	)%
Average Margin for Other (per Mcfe)	$	(1.46	)	$	(0.90	)	$	(0.56	)	(62.2	)%

The Other Gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment also includes purchased gas activity, production royalty interest activity, exploration and other costs, unrealized gain on commodity derivative instruments, other corporate expenses, and miscellaneous operational activity not assigned to a specific E&P segment.

Other gas sales volumes are primarily related to shallow oil and gas production as well as Upper Devonian Shale in Pennsylvania and West Virginia. Outside sales revenue from the other gas segment was approximately $65 million for nine months ended September 30, 2015 compared to $100 million for the nine months ended September 30, 2014. The decrease in outside sales revenue primarily relates to the $1.64 per Mcf decrease in total average sales price. Total costs related to these other sales were $99 million for the nine months ended September 30, 2015 compared to $119 million for the nine months ended September 30, 2014.

Unrealized gain on commodity derivative instruments represents changes in the fair value of all the Company's existing gas commodity hedges on a mark-to-market basis. The unrealized gain on commodity derivative instruments increased $134 million due to the December 31, 2014 de-designation of all derivative positions as cash flow hedges. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.

Production royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P division. Production royalty interest gas sales revenues were $32 million for the nine months ended September 30, 2015 compared to $63 million for the nine months ended September 30, 2014. 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 decrease.



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	16.8		14.6		2.2			15.1	%
Average Sales Price Per thousand cubic feet	$	1.89	$	4.30	$	(2.41	)	(56.0	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $8 million for the nine months ended September 30, 2015 compared to $6 million for the nine months ended September 30, 2014. The period-to-period increase in purchased gas sales revenues was primarily due to the increase in purchased gas sales volumes.



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	2.6		1.1		1.5			136.4	%
Average Sales Price Per thousand cubic feet	$	2.89	$	5.72	$	(2.83	)	(49.5	)%

Miscellaneous other income was $46 million for the nine months ended September 30, 2015 compared to $51 million for the nine months ended September 30, 2014. The $5 million decrease was primarily due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Gathering Revenue	$	10	$	24	$	(14	)	(58.3	)%
Equity in Earnings of Affiliates	32		23		9			39.1	%
Other	4		4		—			—	%
Total Miscellaneous Other Income	$	46	$	51	$	(5	)	(9.8	)%


•	Gathering revenue decreased $14 million primarily due to a decrease in revenue related to certain gathering arrangements.


•	Equity in Earnings of Affiliates increased $9 million primarily due to an increase in earnings from CONE Midstream Partners, LP. and CONE Gathering, LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.


•	Other remained consistent in the period-to-period comparison.

Gain on sale of assets was $3 million for the nine months ended September 30, 2015 compared to $12 million for the nine months ended September 30, 2014. The $9 million decrease was due to various transactions that occurred throughout both periods, none of which were individually material. See Note 2 - Acquisitions and Dispositions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.

General and Administrative costs are allocated to the total E&P division based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $42 million for the nine months ended September 30, 2015 compared to $48 million for the nine months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Production royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P division. Production royalty interest gas costs were $25 million for the nine months

ended September 30, 2015 compared to $54 million for the nine months ended September 30, 2014. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	16.8		14.6		2.2			15.1	%
Average Cost Per thousand cubic feet sold	$	1.48	$	3.68	$	(2.20	)	(59.8	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $6 million for the nine months ended September 30, 2015 compared to $5 million for the nine months ended September 30, 2014.



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	2.6		1.1		1.5			136.4	%
Average Cost Per thousand cubic feet sold	$	2.25	$	4.63	$	(2.38	)	(51.4	)%

Exploration and other costs were $8 million for the nine months ended September 30, 2015 compared to $15 million for the nine months ended September 30, 2014. The $7 million decrease is due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2015		2014		Variance			Percent Change
Land Rentals	$	3	$	4	$	(1	)	(25.0	)%
Lease Expiration Costs	4		5		(1		)	(20.0	)%
Other	1		6		(5		)	(83.3	)%
Total Exploration and Other Costs	$	8	$	15	$	(7	)	(46.7	)%


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


•	Lease expiration costs decreased by $1 million in the period-to-period comparison, primarily due to a decreased number of leases expiring in the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014.


•	The remaining $5 million decrease related to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $895 million for the nine months ended September 30, 2015 compared to $61 million for the nine months ended September 30, 2014. The $834 million increase in the period-to-period comparison was made up of the following items:



	For the Nine Months Ended September 30,
(in millions)	2015		2014			Variance			Percent Change
Impairment of Exploration and Production Properties	$	829	$	—		$	829		100.0	%
Idle Rig Fees	11		—			11			100.0	%
Litigation Settlements	1		(5		)	6			(120.0	)%
Severance Expense	5		—			5			100.0	%
Stock-Based Compensation	11		13			(2		)	(15.4	)%
Unutilized Firm Transportation and Processing Fees	26		29			(3		)	(10.3	)%
Bank Fees	—		4			(4		)	(100.0	)%
Short-Term Incentive Compensation	8		15			(7		)	(46.7	)%
Other	4		5			(1		)	(20.0	)%
Total Other Corporate Expenses	$	895	$	61		$	834		1,367.2	%


•	Impairment of exploration and production properties primarily related to the write down of the Company’s shallow oil and gas asset values. See Note 9 - Property, Plant, And Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information.


•	Idle rig fees are fees related to the temporary idling of some of the Company's natural gas rigs for the nine months ended September 30, 2015. There were no idle rig fees for the nine months ended September 30, 2014.


•	Litigation settlements increased by $6 million in the period-to-period comparison due to various activities that occurred throughout both periods, none of which were individually material.


•	Severance expense was a result of the recent Company reorganization. There was no such expense in the 2014 period.


•	Stock-based compensation decreased $2 million in the period-to-period comparison primarily due to less accelerated expense for retiree eligible employees under our current plans.

•

Unutilized firm transportation costs represent pipeline transportation capacity the E&P division has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. Unutilized firm transportation and processing fees decreased $3 million in the period-to-period comparison due to an increase in the utilization of the capacity.


•	Bank fees decreased $4 million due to the termination of the CNX Gas Senior Secured Credit Agreement on June 18, 2014.


•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for production, safety, and compliance. Short term incentive compensation expense was lower for the 2015 period compared to the 2014 period due to lower payouts.


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

Interest expense related to the E&P division was $5 million for the nine months ended September 30, 2015 compared to $7 million for the nine months ended September 30, 2014. Interest expense was incurred by the other gas segment on interest allocated to the E&P division under CONSOL Energy's credit facility.

TOTAL COAL DIVISION ANALYSIS for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014:

The coal division contributed $356 million of earnings before income tax for the nine months ended September 30, 2015 compared to $287 million of earnings before income tax for the nine months ended September 30, 2014. Variances by the individual coal segment are discussed below.



	For the Nine Months Ended											Difference to Nine Months Ended
	September 30, 2015											September 30, 2014
(in millions)	Pennsylvania Operations			Virginia Operations			Other Coal		Total Coal			Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal
Sales:
Produced Coal	$	1,027		$	193		$	93	$	1,313		$	(200	)	$	(30	)	$	(5	)	$	(235	)
Purchased Coal	—			—			2		2			—			—			(5		)	(5		)
Total Coal Sales	1,027			193			95		1,315			(200		)	(30		)	(10		)	(240		)
Other Outside Sales	—			—			25		25			—			—			(4		)	(4		)
Freight Revenue	6			—			7		13			(9		)	(1		)	—			(10		)
Miscellaneous Other Income	3			—			61		64			(33		)	—			(16		)	(49		)
Gain on Sale of Assets	—			—			51		51			(1		)	—			50			49
Total Revenue and Other Income	1,036			193			239		1,468			(243		)	(31		)	20			(254		)
Cost of Coal Sold:
Operating Costs	573			113			72		758			(98		)	(33		)	(10		)	(141		)
Direct Administrative and Selling	19			4			2		25			(5		)	(1		)	—			(6		)
Total Royalty/Production Taxes	42			11			8		61			(13		)	(3		)	—			(16		)
Depreciation, Depletion and Amortization	126			26			5		157			9			(3		)	—			6
Total Cost of Coal Sold:	760			154			87		1,001			(107		)	(40		)	(10		)	(157		)
Other Costs and Expenses:
Other Costs	(64		)	(28		)	91		(1		)	(68		)	(34		)	(36		)	(138		)
Direct Administrative and Selling	—			—			1		1			(1		)	—			(2		)	(3		)
Total Royalty/Production taxes	—			—			3		3			—			—			2			2
Depreciation, Depletion and Amortization	8			9			22		39			1			3			(2		)	2
Total Other Costs and Expenses:	(56		)	(19		)	117		42			(68		)	(31		)	(38		)	(137		)
General and Administrative Expense	14			3			5		22			(5		)	(3		)	(3		)	(11		)
Other Corporate Expense	18			8			6		32			(11		)	—			1			(10		)
Freight Expense	6			—			7		13			(9		)	(1		)	—			(10		)
Total Coal Costs	742			146			222		1,110			(200		)	(75		)	(50		)	(325		)
Interest Expense	2			—			—		2			2			—			—			2
Total Coal Division Costs	744			146			222		1,112			(198		)	(75		)	(50		)	(323		)
Earnings Before Income Taxes	$	292		$	47		$	17	$	356		$	(45	)	$	44		$	70		$	69

PENNSYLVANIA (PA) OPERATIONS COAL SEGMENT

The PA Operations coal segment's principal activities consist of mining, preparation and marketing of thermal coal to power generators. The segment also includes general and administrative activities as well as various other activities assigned to the PA Operations coal segment but not allocated to each individual mine and, therefore, are not included in unit cost presentation. For the nine months ended September 30, 2015 and 2014 the segment included the following mines: Bailey Mine, Enlow Fork Mine, Harvey Mine and the corresponding preparation plant facilities.

The PA Operations coal segment contributed $292 million of earnings before income tax for the nine months ended September 30, 2015 compared to $337 million of earnings before income tax for the nine months ended September 30, 2014. The PA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Company Produced PA Operations Tons Sold (in millions)	17.9		19.6		(1.7		)	(8.7	)%
Average Sales Price Per PA Operations Ton Sold	$	57.41	$	62.47	$	(5.06	)	(8.1	)%

Total Operating Costs Per Ton Sold	$	32.23	$	34.15	$	(1.92	)	(5.6	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.05		1.23		(0.18		)	(14.6	)%
Total Royalty/Production Taxes Per Ton Sold	2.28		2.79		(0.51		)	(18.3	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.92		5.96		0.96			16.1	%
Total Costs Per PA Operations Ton Sold	$	42.48	$	44.13	$	(1.65	)	(3.7	)%
Average Margin Per PA Operations Ton Sold	$	14.93	$	18.34	$	(3.41	)	(18.6	)%

Coal Sales

PA Operations produced coal outside sales revenues were $1,027 million for the nine months ended September 30, 2015, compared to $1,227 million for the nine months ended September 30, 2014. The $200 million decrease was attributable to a $5.06 per ton lower average sales price and a 1.7 million decrease in tons sold. The lower average coal sales price per ton sold in the current period was primarily the result of the continued decline in the domestic and global thermal coal markets.

Freight Revenue

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, primarily rail, used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $6 million for the nine months ended September 30, 2015, compared to $15 million for the nine months ended September 30, 2014. The $9 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

Miscellaneous other income decreased by $33 million in the period-to-period comparison primarily due to a $30 million coal customer contract buyout that occurred during the nine months ended September 30, 2014. The discontinued contract was a long term contract that created pricing risks for both parties. The remaining $3 million decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Gain on Sale of Assets

Gain on sale of assets decreased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Cost of Coal Sold

cost of coal sold for PA Operations was $760 million for the nine months ended September 30, 2015, or $107 million lower than the $867 million for the nine months ended September 30, 2014. Total costs per PA Operations ton sold was $42.48 per ton for the nine months ended September 30, 2015, compared to $44.13 per ton for the nine months ended September 30, 2014. The decrease in total dollars and unit costs was primarily due to the decrease of 1.7 million tons sold, which partially resulted from PA Operations moving to a four-day work week in May 2015, compared to a normal five-day per week schedule in order to preserve margins. Total cost of coal sold also decreased due to better geological conditions, a reduced workforce, and other ongoing cost reduction efforts. Unit costs decreased as a result of the Pension and OPEB plan modifications for active employees in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Costs And Expenses

Other costs are comprised of various costs and expenses that are assigned to the PA Operations coal segment, but not allocated to each individual mine and, therefore, not included in unit costs. Other costs, including certain administrative expenses and depreciation, depletion, and amortization, decreased $68 million during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, primarily related to $79 million of income related to modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information. The income was offset, in part, by $8 million of accelerated amortization of financing charges related to a backstop loan which was terminated on July 7, 2015. The remaining variance was due to various items that occurred throughout both periods, none of which were individually material. There was also a decrease in the unit costs as a result of the Pension and OPEB plan modifications for active employees in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

General and Administrative Expense

General and Administrative costs are allocated to each coal segment based upon the activity at the segment determined by their level of operating activity. Upon execution of the CNXC IPO, CNXC entered into a service arrangement with CONSOL Energy to provide certain general and administrative services. These services are paid monthly based on an agreed upon fixed fee that is reset annually. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information. The amount of General and Administrative costs related to PA Operations was $14 million for the nine months ended September 30, 2015, compared to $19 million for the nine months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expense is comprised of expenses for stock based compensation and the short-term incentive compensation program. These expenses include costs that are directly related to each coal segment along with a portion of costs that are allocated to each segment based on a percent of total labor dollars. For the nine months ended September 30, 2015, other corporate expenses were $18 million compared to $29 million for the nine months ended September 30, 2014. The decrease of $11 million was primarily due to PA Operations representing a smaller portion of total coal labor dollars and lower short-term incentive compensation payouts.

Freight Expense

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation, primarily rail, 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. For the nine months ended September 30, 2015, freight expense was $6 million compared to $15 million for the nine months ended September 30, 2014. The $9 million decrease was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Interest Expense

Interest expense is comprised of interest on CNXC revolving credit facility. Upon execution of the CNXC initial public offering on July 7, 2015, CNXC drew down an initial $200,000 on the credit facility and incurred interest expense for the nine months ended September 30, 2015. No such expense was incurred for the nine months ended September 30, 2014.

VIRGINIA (VA) OPERATIONS COAL SEGMENT

The VA Operations coal segment's principal activities consist of mining, preparation and marketing of low volatile metallurgical coal to metal and coke producers. The segment also includes general and administrative activities as well as various other activities assigned to the VA Operations coal segment but not allocated to each individual mine and, therefore, are not included in unit cost presentation. For the nine months ended September 30, 2015 and 2014, the segment included Buchanan Mine and the corresponding preparation plant facilities.

The VA Operations coal segment contributed $47 million of earnings before income tax for the nine months ended September 30, 2015, compared to earnings before income tax of $3 million for the nine months ended September 30, 2014. The VA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Company Produced VA Operations Tons Sold (in millions)	3.2		3.1		0.1			3.2	%
Average Sales Price Per VA Operations Ton Sold	$	59.61	$	72.95	$	(13.34	)	(18.3	)%

Total Operating Costs Per Ton Sold	$	35.05	$	47.48	$	(12.43	)	(26.2	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.19		1.49		(0.30		)	(20.1	)%
Total Royalty/Production Taxes Per Ton Sold	3.44		4.51		(1.07		)	(23.7	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	8.04		9.59		(1.55		)	(16.2	)%
Total Costs Per VA Operations Ton Sold	$	47.72	$	63.07	$	(15.35	)	(24.3	)%
Average Margin Per VA Operations Ton Sold	$	11.89	$	9.88	$	2.01		20.3	%

Coal Sales

VA Operations produced coal outside sales revenues were $193 million for the nine months ended September 30, 2015, compared to $223 million for the nine months ended September 30, 2014. The $30 million decrease was primarily attributable to a $13.34 per ton lower average sales price, offset, in part, by an increase of 0.1 million tons sold in the period-to-period comparison. Average sales prices for VA Operations coal decreased in the period-to-period comparison due to the continued weakening in the global metallurgical coal market.

Freight Revenue

There was no freight revenue for the nine months ended September 30, 2015. Freight revenue was $1 million for the nine months ended September 30, 2014. The decrease in the period-to-period comparison was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Cost of Coal Sold

Total cost of coal sold for VA Operations was $154 million for the nine months ended September 30, 2015, or $40 million lower than the $194 million for the nine months ended September 30, 2014. Total costs per VA Operations ton sold were $47.72 per ton in the nine months ended September 30, 2015, compared to $63.07 per ton for the nine months ended September 30, 2014. The decrease in total dollars and unit costs per VA Operations ton sold was primarily due to a modification of the operating shifts at the Buchanan Mine and other cost control measures that were implemented due to the weak metallurgical coal market. The mine went from three operating shifts to two operating shifts beginning in May 2014, which resulted in lower wage and wage related expenses, royalty and production taxes, and maintenance and supply costs, as well as a reduction in the number of degas wells drilled and gallons of wastewater treated. Also contributing to the decrease was the effect of the Pension and OPEB plan modifications for active employees in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information.

Other Costs And Expenses

Other costs, including certain administrative expense and depreciation, depletion, and amortization, decreased $31 million during the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014, primarily attributable

to $40 million of income due to modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information. The remaining $9 million increase was due to a $3 million increase in various legal fees, a $4 million increase in water treatment costs (including depreciation, depletion, and amortization) and various other transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and Administrative costs allocated to the VA Operations coal segment were $3 million for the nine months ended September 30, 2015, compared to $6 million for the nine months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses remained consistent in the period-to-period comparison.

Freight Expense

There was no freight expense for the nine months ended September 30, 2015. Freight expense was $1 million for the nine months ended September 30, 2014. The decrease was due to decreased shipments where CONSOL Energy contractually provides transportation services.

OTHER COAL SEGMENT

The Other coal segment primarily includes coal terminal operations, idle mine activities and purchased coal activities, as well as various other activities not assigned to either PA Operations or VA Operations. The Other coal segment also includes activities related to mining, preparation and marketing of thermal coal to power generators geographically separated from PA Operations. For the nine months ended September 30, 2015 and 2014, the segment included the Miller Creek Complex.

The Other coal segment contributed $17 million of earnings before income tax for the nine months ended September 30, 2015, compared to a loss before income tax of $53 million for the nine months ended September 30, 2014. Other coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Nine Months Ended September 30,
	2015		2014		Variance			Percent Change
Company Produced Other Operations Tons Sold (in millions)	1.6		1.6		—			—	%
Average Sales Price Per Other Operations Ton Sold	$	59.84	$	60.36	$	(0.52	)	(0.9	)%

Total Operating Costs Per Ton Sold	$	46.29	$	50.04	$	(3.75	)	(7.5	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.01		1.20		(0.19		)	(15.8	)%
Total Royalty/Production Taxes Per Ton Sold	5.07		5.12		(0.05		)	(1.0	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	2.92		3.35		(0.43		)	(12.8	)%
Total Costs Per Other Operations Ton Sold	$	55.29	$	59.71	$	(4.42	)	(7.4	)%
Average Margin Per Other Operations Ton Sold	$	4.55	$	0.65	$	3.90		600.0	%

Coal Sales

Other produced coal outside sales revenues were $93 million for the nine months ended September 30, 2015, compared to $98 million for the nine months ended September 30, 2014. The $5 million decrease was attributable to a $0.52 per ton lower average sales price. The lower average coal sales price in the current period was the result of the overall decline in the domestic thermal coal markets.

Purchased coal sales consisted of revenues from coal purchased from third parties and sold directly to CONSOL Energy's customers. These revenues were $2 million for the nine months ended September 30, 2015, compared to $7 million for the nine months ended September 30, 2014. The $5 million decrease in the period-to-period comparison was a result of lower coal volumes that needed to be purchased to fulfill various contracts.

Other Outside Sales Revenue

Other outside sales revenue consists of revenues from the Company's coal terminal operations. Coal terminal operations sales revenues were $25 million for the nine months ended September 30, 2015, compared to $29 million for the nine months ended September 30, 2014. The $4 million decrease in the period-to-period comparison was primarily due to a decrease in thru-put volumes in the current quarter.

Freight Revenue

Freight revenue remained consistent in the period-to-period comparison.

Miscellaneous Other Income

Miscellaneous other income was $61 million for the nine months ended September 30, 2015, compared to $77 million for the nine months ended September 30, 2014. The change is due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2015		2014		Variance
Equity in Earnings of Affiliates	$	7	$	17	$	(10	)
Rental Income	26		33		(7		)
Royalty Income	13		15		(2		)
Right of Way Sales	8		4		4
Other	7		8		(1		)
Total Other Income	$	61	$	77	$	(16	)


•	Equity in earnings of affiliates decreased $10 million due to the sale of the Company's interest in two equity affiliates in October 2014.


•	Rental income decreased $7 million due to the buyout of certain equipment that was leased by CONSOL Energy and then subleased to a third-party in 2014.


•	Royalty income decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Right of way sales increased $4 million due to additional revenue earned from the sale of several right of ways during the nine months ended September 30, 2015.


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

Gain on Sale of Assets

Gain on sale of assets increased $50 million in the period-to-period comparison, primarily due to the sale of the Company's 49% interest in Western Allegheny Energy. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

Cost of Coal Sold

Total cost of coal sold attributable to the Other coal segment was $87 million for the nine months ended September 30, 2015, or $10 million lower than the $97 million for the nine months ended September 30, 2014. Total costs per Other Operations ton sold were $55.29 per ton for the nine months ended September 30, 2015, compared to $59.71 per ton for the nine months ended September 30, 2014. The decrease in cost of coal sold was primarily the result of the Pension and OPEB plan modifications for active employees in September 2014.

Other Costs And Expenses

Other costs and expenses related to the Other coal segment were $117 million for the nine months ended September 30, 2015, compared to $155 million for the nine months ended September 30, 2014. The decrease of $38 million was due to the following items:



	For the Nine Months Ended September 30,
	2015			2014		Variance
OPEB Plan Changes	$	(16	)	$	—	$	(16	)
Purchased Coal	1			12		(11		)
UMWA OPEB Expense	35			39		(4		)
Coal Terminal Operations	15			19		(4		)
Lease Rental Expense	20			23		(3		)
Closed and Idle Mines	35			38		(3		)
Depreciation, Depletion & Amortization	22			24		(2		)
Other	5			—		5
Total Other Costs	$	117		$	155	$	(38	)


•	Income of $16 million related to OPEB plan changes was the result of modifications made to the OPEB plan in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information.


•	Purchased coal costs decreased $11 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.


•	UMWA OPEB expense decreased $4 million primarily due to a decrease in interest costs.


•	Coal terminal operations costs decreased $4 million due to decreased thru-put volumes in the current period.


•	Lease rental expense decreased $3 million primarily due to the buyout of certain equipment that was leased by CONSOL Energy.

•

Closed and idle mine costs decreased $3 million primarily due to a $6 million decrease in property taxes and a $4 million decrease in permitting and compliance costs. The decrease was offset, in part, by an $8 million increase in asset retirement obligations expense, primarily related to a reduction of the asset retirement obligation at the Fola Mining Complex during the nine months ended September 30, 2014. The remaining increase was due to various transactions that occurred throughout both periods, none of which were individually material.


•	Depreciation, depletion, and amortization decreased $2 million primarily due to fewer assets placed in service in the period-to-period comparison.


•	Other increased $5 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and Administrative costs allocated to the Other coal segment were $5 million for the nine months ended September 30, 2015, compared to $8 million for the nine months ended September 30, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses were $6 million for the nine months ended September 30, 2015, compared to $5 million for the nine months ended September 30, 2014. The $1 million increase was due to various transactions that occurred throughout both periods, none of which were individually material.

Freight Expense

Freight expense remained consistent in the period-to-period comparison.

OTHER DIVISION ANALYSIS for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014:

The other division includes expenses from various other corporate activities that are not allocated to the E&P or coal divisions. The other division had a loss before income tax of $248 million for the nine months ended September 30, 2015 compared to a loss before income tax of $321 million for the nine months ended September 30, 2014. The other division also includes a total Company income tax benefit of $259 million for the nine months ended September 30, 2015 compared to income tax expense of $8 million for the nine months ended September 30, 2014.



	For the Nine Months Ended
(in millions)	2015			2014			Variance			Percent Change
Sales—Outside	$	—		$	184		$	(184	)	(100.0	)%
Other Income	2			2			—			—	%
Total Revenue	2			186			(184		)	(98.9	)%
Miscellaneous Operating Expense	39			246			(207		)	(84.1	)%
Depreciation, Depletion & Amortization	—			2			(2		)	(100.0	)%
Loss on Debt Extinguishment	68			95			(27		)	(28.4	)%
Interest Expense	143			164			(21		)	(12.8	)%
Total Other Costs	250			507			(257		)	(50.7	)%
Loss Before Income Tax	(248		)	(321		)	73			(22.7	)%
Income Tax	(259		)	8			(267		)	(3,337.5	)%
Net Income (Loss)	$	11		$	(329	)	$	340		(103.3	)%

There were no outside sales revenues from the other division for the nine months ended September 30, 2015 compared to $184 million for the nine months ended September 30, 2014. The decrease of $184 million was primarily related to the divestiture of our industrial supplies subsidiary in December 2014.

Other Income remained consistent in the period-to-period comparison.

Total other costs related to the other division were $250 million for the nine months ended September 30, 2015 compared to $507 million for the nine months ended September 30, 2014. Other costs decreased due to the following items:



	For the Nine Months Ended
(in millions)	2015		2014		Variance
Industrial Supplies	$	—	$	181	$	(181	)
Loss on Debt Extinguishment	68		95		(27		)
Pension Settlement	3		25		(22		)
Interest Expense	143		164		(21		)
Long-Term Liability Plan Changes	—		10		(10		)
Revolver Modification Fees	—		3		(3		)
Bank Fees	13		15		(2		)
Severance Expense	5		—		5
Transaction Fees	5		—		5
Pension Expense	9		—		9
Other	4		14		(10		)
	$	250	$	507	$	(257	)


•	There were no Industrial Supplies costs in the nine months ended September 30, 2015 and $181 million in the nine months ended September 30, 2014. The decrease is due to the divestiture of our industrial supplies subsidiary in December 2014.


•	In the nine months ended September 30, 2015, CONSOL Energy partially purchased the 8.25% senior notes that were due in 2020 at an average price equal to 104.6% of the principal amount and the 6.375% senior notes that were due in 2021 at an average price equal to 105.0% of the principal amount resulting in a loss on debt extinguishment of $68 million.

In the nine months ended September 30, 2014, CONSOL Energy purchased all of the 8% senior notes that were due 2017 at an average price equal to 104.0% and partially purchased the 8.25% senior notes that were due 2020 at an average price equal to 107.5% resulting in a loss on debt extinguishment of $95 million.


•	Pension settlement decreased $22 million in the period-to-period comparison. See Note 4 - Components of Pension and OPEB Plans Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense.

•

Interest expense decreased $21 million in the period-to-period comparison primarily due to the partial payoff of the 2020 and 2021 bonds in the nine months ended September 30, 2015 and the payoff of the 2017 bonds issued in April 2014 and the partial payoff of the 2020 bonds issued in August 2014. The decrease in interest expense is also due to lower interest rates on the newly issued 2023 bonds issued in March 2015 and the 2022 bonds issued in April and August 2014. The decrease was offset, in part, by a decrease in capitalized interest related to the Harvey Mine going into production in 2014.


•	Long-term liability plan changes during the nine months ended September 30, 2014 include $46 million of expense for cash payments made to active employees related to changes in the OPEB plan. This expense was partially offset by $36 million of income as a result of curtailment associated with amendments to the pension and OPEB plans adopted during the third quarter of 2014.


•	Revolver modification fees in the nine months ended September 30, 2014 related to a $3 million non-cash charge associated with entering into a new senior secured credit facility. The charge was related to acceleration of previously deferred financing fees.


•	Bank fees decreased by $2 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Severance payments were $5 million for the nine months ended September 30, 2015 due to the Company reorganization in the current period.


•	Transaction fees increased by $5 million in the nine months ended September 30, 2015, related to fees associated with various corporate initiatives including the recent CNXC MLP.

•

Actuarially-calculated amortization of $9 million was included in the Other Division in the nine months ended September 30, 2015 due to modifications made to the Pension plan in September 2014. Refer to the discussion of total Company long-term liabilities contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this Quarterly Report on Form 10-Q for more information.


•	Other corporate items decreased $10 million due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 39.4% for the nine months ended September 30, 2015 compared to 8.0% for the nine months ended September 30, 2014. The effective rates for the nine months ended September 30, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. For the nine months ended September 30, 2015, CONSOL Energy recognized certain tax benefits related to a prior-year tax provision. These changes resulted in an expense of $27 million related to decreased percentage depletion deductions, offset, in part, by $5 million of tax benefit due to changes in the deduction for certain stock-related compensation.

For the nine months ended September 30, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. That resulted in a benefit of $8 million related to increased percentage of depletion deductions, offset, in part, by $1 million of tax expense due to changes in the Domestic Production Activities Deduction. Also, the Internal Revenue Service issued its audit report relating to the examination of CONSOL Energy's 2008 and 2009 U.S. income tax returns during the nine months ended September 30, 2014. The result of these findings was a change in timing of certain tax deductions which increased the tax benefit of percentage of depletion by $7 million. Also, as a result of closing the IRS audit, CONSOL Energy was required to file amended state income tax returns. The Company filed the required amended returns and realized a discrete state income tax charge of $5 million which was offset by a federal income tax benefit of $2 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.

standards of positive and negative evidence. If it is determined that it is more likely than not that a deferred tax asset will be realized, the appropriate amount of the valuation allowance, if any, is released. Deferred tax assets and liabilities are also re-measured to reflect changes in underlying tax rates due to law changes.



	For the Nine Months Ended
(in millions)	2015			2014			Variance			Percent Change
Total Company Earnings Before Income Tax	$	(658	)	$	103		$	(762	)	(736.4	)%
Income Tax (Benefit) Expense	$	(259	)	$	8		$	(268	)	(3,219.5	)%
Effective Income Tax Rate	39.4		%	8.0		%	31.4		%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On June 18, 2014, CONSOL Energy entered into a Credit Agreement for a $2.0 billion senior secured revolving credit facility. This Agreement expires on June 18, 2019. 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 $2.0 billion of borrowings, which includes $750 million letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy's proved gas reserves. 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 Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries excluding CNXC. The interest coverage ratio was 4.86 to 1.00 at September 30, 2015. Adjusted 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, losses on debt extinguishment and includes cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver. This calculation also excludes all of CNXC's current assets, current liabilities, and revolver availability. The current ratio was 1.96 to 1.00 at September 30, 2015. Affirmative and negative covenants in the facility limit the Company's 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. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems. The facility permits CONSOL Energy to separate its gas and coal businesses if the leverage ratio (which, is essentially, the ratio of debt to EBITDA) of the gas business immediately after the separation would not be greater than 2.75 to 1.00. At September 30, 2015, the facility had $945 million of borrowings outstanding and $281 million of letters of credit outstanding, leaving $774 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies' statutes and regulations. CONSOL Energy sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

In May 2015, the facility was amended to allow, among other things, spinoffs, or other public equity offering transactions, in regard to subsidiaries that own metallurgical coal assets and thermal coal assets, and all arrangements, actions and transactions in connection therewith, including releases of associated entities or assets from the Credit Agreement and any liens granted under the loan documents.

CONSOL Energy terminated its accounts receivable securitization facility effective July 7, 2015. The outstanding borrowings at June 30, 2015 were repaid, and the outstanding letters of credit at June 30, 2015 were transferred against the revolving credit facility.

CONSOL Energy has completed the refinancing of approximately $5.0 billion of short and long-term borrowings since the second quarter of 2014.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in the Company's stock price, less availability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions may impact the Company's collection of trade receivables. As a result, CONSOL Energy regularly monitors the creditworthiness of its customers. CONSOL Energy believes that its current group of customers are financially sound and represent no abnormal business risk.

CONSOL Energy believes that cash generated from operations, asset sales and the Company's borrowing capacity will be sufficient to meet the Company's 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 gas and coal 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 and option transactions, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $231 million at September 30, 2015. No issues related to the Company's hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Nine Months Ended September 30,
	2015			2014			Change
Cash flows from operating activities	$	404		$	850		$	(446	)
Cash used in investing activities	$	(882	)	$	(925	)	$	43
Cash provided by (used in) financing activities	$	384		$	(27	)	$	411

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


•	Net income decreased $488 million in the period-to-period comparison.

•

Adjustments to reconcile net income to cash flow provided by operating activities increased $829 million due to the impairment of exploration and production properties (See Note 9 - Property, Plant, And Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information), offset, in part, by a a decrease of $288 million related to changes in deferred taxes, a decrease of $134 million due to the unrealized gain on commodity derivative instruments, a decrease of $116 million in other post-employment benefits plan amendments, and additional depreciation, depletion, and amortization of $42 million.


•	Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods also contributed to the decrease 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 decreased $279 million in the period-to-period comparison due to:


◦	Gas segment capital expenditures decreased $103 million. This is due to decreased expenditures in the Marcellus play along with decreased land expenditures, partially offset by increased expenditures in the Utica play and increased gathering expenditures, as well as other various transactions that occurred throughout both periods.

◦

Coal segment capital expenditures decreased $181 million. This was comprised of a $107 million decrease of equipment expenditures at the Harvey Mine mainly due to the acquisition of the Harvey Mine longwall shields in 2014. Capital projects at the Harvey Mine also decreased $43 million due to its completion in the first quarter of 2014. Capitalized interest decreased $11 million due to the completion of the Harvey Mine. The remaining $20 million decrease is due to various other projects that occurred throughout both periods.


◦	Other capital expenditures increased $5 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Proceeds from the sale of assets decreased $58 million in the period-to-period comparison primarily due to $75 million received in March 2014 related to the Harvey Mine shield sale-leaseback as well as $46 million received in January 2014 as reimbursement from Noble Energy for 50% of the Dominion Resources lease acquisition and $14 million

received in June 2014 related to the McElroy shields buyout. These decreases were offset, in part, by an increase of $76 million received in September 2015 related to the sale of CONSOL Energy's interest in its Western Allegheny Energy joint venture as well as various other transactions that occurred throughout both periods. See Note 2 - Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information. The remaining increase was due to various items that occurred throughout both periods, none of which were individually material.

•

Cash provided by equity affiliates decreased $179 million primarily due to a $157 million decrease in return of investments due to the IPO of CONE Midstream Partners, LP occurring in September 2014 along with an $18 million reduction in net equity due to the sale of the Company's interest in the Western Allegheny Energy joint venture in September 2015 and $4 million less of distributions received from various equity partners in the period ended September 30, 2015 compared to the period ended September 30, 2014.

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


•	In the nine months ended September 30, 2015, CONSOL Energy received $945 million of proceeds from the senior secured credit facility compared to payments on the facility of $12 million in the nine months ended September 30, 2014.

•

In the nine months ended September 30, 2015, CONSOL Energy had net payments of $771 million related to the partial extinguishment of the 2020 and 2021 bonds offset, in part, by the issuance of the 2023 bonds. In the nine months ended September 30, 2014, CONSOL Energy had net proceeds from long-term borrowings of $41 million. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.


•	In the nine months ended September 30, 2015, CONSOL Energy received $180 million of net proceeds under the CNX Coal Resources LP credit facility.


•	In the nine months ended September 30, 2015, CONSOL Energy received proceeds of $148 million from the IPO of CNX Coal Resources LP.


•	In the nine months ended September 30, 2015, CONSOL Energy repurchased $72 million of its common stock on the open market under the previously announced share repurchase program. No repurchases were made as of September 30, 2014.


•	In the nine months ended September 30, 2015, CONSOL Energy paid three quarterly dividends totaling $31 million at an amount per share of $0.1350. In the nine months ended September 30, 2014, CONSOL Energy paid three quarterly dividends totaling $43 million at an amount per share of $0.1875.


•	The remaining changes are due to various transactions that occurred throughout both periods.

The following is a summary of our significant contractual obligations at September 30, 2015 (in thousands):



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase Order Firm Commitments	$	85,695	$	71,265	$	7,042	$	682	$	164,684
Gas Firm Transportation and Processing	122,121		207,139		183,719		552,584		1,065,563
Long-Term Debt	4,221		6,071		255,835		2,477,385		2,743,512
Interest on Long-Term Debt	158,300		336,243		335,105		390,864		1,220,512
Capital (Finance) Lease Obligations	8,192		15,412		14,365		7,610		45,579
Interest on Capital (Finance) Lease Obligations	2,628		4,082		2,224		325		9,259
Operating Lease Obligations	102,050		163,035		56,580		72,814		394,479
Long-Term Liabilities—Employee Related (a)	89,539		128,361		165,178		549,891		932,969
Other Long-Term Liabilities (b)	222,013		225,978		76,991		347,809		872,791
Total Contractual Obligations (c)	$	794,759	$	1,157,586	$	1,097,039	$	4,399,964	$	7,449,348

_________________________

(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. Additional contributions to the pension trust are not expected to be significant for the remainder of 2015.


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


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

Debt

At September 30, 2015, CONSOL Energy had total long-term debt and capital lease obligations of $2,789 billion outstanding, including the current portion of long-term debt of $12 million. This long-term debt consisted of:


•	An aggregate principal amount of $74 million 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 is guaranteed by most of CONSOL Energy’s subsidiaries.


•	An aggregate principal amount of $21 million of 6.375% senior unsecured 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 is guaranteed by most of CONSOL Energy's subsidiaries.


•	An aggregate principal amount of $1,850 million of 5.875% senior unsecured notes due in April 2022 plus $6 million of unamortized bond premium. Interest on the notes is payable April 15 and October 15 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy's subsidiaries.


•	An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $7 million of unamortized bond discount. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is 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 $13 million with an average interest rate of 7.91% per annum.


•	An aggregate principal amount of $3 million on a note maturing through March 2018.


•	An aggregate principal amount of $46 million of capital leases with a weighted average interest rate of 5.77% per annum.


•	An aggregate principal amount of $180 million in outstanding borrowings under the revolver for CNXC. CONSOL Energy is not a guarantor of CNXC's revolving credit facility

At September 30, 2015, CONSOL Energy had an aggregate principal amount of $945 million in outstanding borrowings and approximately $281 million of letters of credit outstanding under the $2.0 billion senior secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $4.9 billion at September 30, 2015 and $5.3 billion at December 31, 2014. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

Consistent with what the Company previously announced on December 10, 2014 and in connection with the initial public offering of CNX Coal Resources LP , CONSOL Energy reduced its current regular dividend to $0.01 per share, per quarter, effective in the third quarter of 2015.

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



Declaration Date	Amount Per Share		Record Date	Payment Date
October 28, 2015	$	0.0100	November 12, 2015	November 20, 2015
July 29, 2015	$	0.0100	August 10, 2015	August 24, 2015
April 29, 2015	$	0.0625	May 11, 2015	May 21, 2015
February 2, 2015	$	0.0625	February 17, 2015	March 5, 2015

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. The Company's credit facility limits CONSOL Energy's ability to pay dividends in excess of an annual rate of $0.50 per share when the Company's leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 3.86 to 1.00 and the cumulative credit was approximately $935 million at September 30, 2015. The calculation of this ratio excludes CNXC. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per share annually unless several conditions

are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the three months ended September 30, 2015.

Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan which generally accepted accounting principles recognize on a pay-as-you-go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at September 30, 2015. The various multi-employer benefit plans are discussed in Note 18—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2014 Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure the Company's financial obligations for employee-related, environmental, performance and various other items which are not reflected on the consolidated balance sheet at September 30, 2015. Management believes these items will expire without being funded. See Note 12—Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” "will,"or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:


•	deterioration in economic conditions in any of the industries in which our customers operate may decrease demand for our products, impair our ability to collect customer receivables and impair our ability to access capital;

•

prices for natural gas, natural gas liquids and coal are volatile and can fluctuate widely based upon a number of factors beyond our control including oversupply relative to the demand available for our products, weather and the price and availability of alternative fuels. An extended decline in the prices we receive for our natural gas, natural gas liquids and coal affecting our operating results and cash flows;


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


•	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 natural gas and coal to market;


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


•	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 natural gas and coal;


•	the risks inherent in natural gas and coal operations, including our reliance upon third party contractors, 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;


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


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


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


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


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


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


•	increased exposure to employee-related long-term liabilities;


•	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 asset monetization transactions, including sales of additional interests in our thermal coal or other assets to CNX Coal Resources LP and divestitures to third parties 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;


•	risks associated with our debt;


•	replacing our gas and oil reserves, which if not replaced, will cause our gas and oil reserves and 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;


•	failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition;


•	failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows;


•	information theft, data corruption, operational disruption and/or financial loss resulting from a terrorist attack or cyber incident;


•	operating in a single geographic area; and


•	other factors discussed in the 2014 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL Energy uses fixed-price contracts, options and derivative commodity instruments to minimize exposure to market price volatility in the sale of natural gas. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. 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 2014 Form 10-K.

At September 30, 2015, our open derivative instruments were in a net asset position with a fair value of $231.4 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at September 30, 2015. A hypothetical 10 percent increase in future natural gas prices would decrease pre-tax future earnings related to derivatives by $102.8 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At September 30, 2015, CONSOL Energy had $2,609 billion aggregate principal amount of debt outstanding under fixed-rate instruments and $1,125 million 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 $945.0 million of borrowings at September 30, 2015 and CNXC revolving credit facility under which there were $180 million of borrowings at September 30, 2015. A hypothetical 100 basis-point increase in the average rate for CONSOL Energy's and CNXC's revolving credit facility would decrease pre-tax future earnings related to interest expense by $8.2 million.

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

Hedging Volumes

As of October 9, 2015, our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2015 Fixed Price Volumes
Hedged Mcf	N/A		N/A		N/A		63,304,762		63,304,762
Weighted Average Hedge Price per Mcf	N/A		N/A		N/A		$	3.44	$	3.44
2016 Fixed Price Volumes
Hedged Mcf	55,696,798		55,696,798		56,308,851		56,308,851		224,011,298
Weighted Average Hedge Price per Mcf	$	3.44	$	3.23	$	3.23	$	3.40	$	3.33
2017 Fixed Price Volumes
Hedged Mcf	14,844,486		15,009,425		15,174,364		15,174,364		60,202,639
Weighted Average Hedge Price per Mcf	$	3.30	$	3.30	$	3.30	$	3.30	$	3.30
2018 Fixed Price Volumes
Hedged Mcf	5,023,256		5,079,070		5,134,884		5,134,884		20,372,094
Weighted Average Hedge Price per Mcf	$	3.28	$	3.28	$	3.28	$	3.28	$	3.28


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of September 30, 2015 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II: OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

The first through the ninth paragraphs of Note 12—Commitments and Contingent Liabilites in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth repurchases of our common stock during the nine months ended September 30, 2015:



ISSUER PURCHASES OF EQUITY SECURITIES
	(a)	(b)		(c)	(d)
Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (000's omitted) (2)
January 1, 2015 - January 31, 2015	—	—		—	$	250,000
February 1, 2015 - February 28, 2015	1,693,100	$	32.92	1,693,100	$	194,269
March 1, 2015 - March 31, 2015	520,000	$	30.57	2,213,100	$	178,370
Total	2,213,100	$	32.37

(1) On December 10, 2014, CONSOL Energy's Board of Directors approved a two-year share repurchase program of up to $250 million. The repurchases will be effected from time-to-time on the open market or in privately negotiated transactions or under a Rule 10b5-1 plan.

(2) Management cannot estimate the number of shares that will be repurchased because purchases are made based upon the Company's stock price, the Company's financial outlook and alternative investment options.

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			Amended and Restated Change in Control Severance Agreement, dated as of October 9, 2015, between CONSOL Energy Inc., and David M. Khani.

10.2			Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL Energy Inc., and Timothy Dugan.

10.3			Amended and Restated Change in Control Severance Agreement, dated as of August 24, 2015, between CONSOL Energy Inc., and James A. Brock.

31.1			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95			Mine Safety and Health Administration Safety Data.

101			Interactive Data File (Form 10-Q for the quarterly period ended September 30, 2015 furnished in XBRL).

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

SIGNATURES

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

Dated: November 3, 2015



	CONSOL ENERGY INC.

	By:		/s/ NICHOLAS J. DEIULIIS
			Nicholas J. DeIuliis
			Chief Executive Officer and President and Director (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/ C. KRISTOPHER HAGEDORN
			C. Kristopher Hagedorn
			Controller (Duly Authorized Officer and Principal Accounting Officer)

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