CNX 10-Q Quarterly Report June 30, 2015

CNX RESOURCES CORP

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on May 1, 2025
DEF 14A	Filed on March 20, 2025
DEF 14A	Filed on May 2, 2024
DEF 14A	Filed on March 21, 2024
DEF 14A	Filed on March 23, 2023
DEF 14A	Filed on May 5, 2022
DEF 14A	Filed on March 24, 2022
DEF 14A	Filed on March 23, 2021
DEF 14A	Filed on March 24, 2020
DEF 14A	Filed on April 18, 2019
DEF 14A	Filed on March 29, 2018
DEF 14A	Filed on April 3, 2017
DEF 14A	Filed on April 1, 2016
DEF 14A	Filed on March 25, 2015
DEF 14A	Filed on March 28, 2014
DEF 14A	Filed on March 29, 2013
DEF 14A	Filed on March 26, 2012
DEF 14A	Filed on March 28, 2011
DEF 14A	Filed on March 19, 2010

10-Q 1 cnx-63015x10q.htm 10-Q CNX-6.30.15-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended June 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 July 17, 2015
Common stock, $0.01 par value		229,004,060

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2015 and 2014.	3
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2015 and 2014.	4
	Consolidated Balance Sheets at June 30, 2015 and December 31, 2014.	5
	Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2015	7
	Consolidated Statements of Cash Flows for the six months ended June 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	37

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	87

ITEM 4.	Controls and Procedures	88

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	88

ITEM 1A.	Risk Factors	88

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	92

ITEM 4.	Mine Safety Disclosures	92

ITEM 5.	Other Information	93

ITEM 6.	Exhibits	94

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						Six Months Ended
(Unaudited)	June 30,						June 30,
Revenues and Other Income:	2015			2014			2015			2014
Natural Gas, NGLs and Oil Sales	$	201,911		$	229,743		$	456,491		$	496,041
Unrealized (Loss) Gain on Commodity Derivative Instruments	(24,936		)	—			35,068			—
Coal Sales	414,480			536,298			911,146			1,070,979
Other Outside Sales	6,337			70,087			19,467			139,374
Production Royalty Interests and Purchased Gas Sales	6,887			19,739			25,343			49,958
Freight-Outside Coal	4,251			10,109			10,776			20,054
Miscellaneous Other Income	35,694			69,977			73,760			125,031
Gain on Sale of Assets	4,315			1,417			6,480			5,086
Total Revenue and Other Income	648,939			937,370			1,538,531			1,906,523
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	25,319			26,374			56,931			55,617
Transportation, Gathering and Compression	86,979			57,796			165,723			111,578
Production, Ad Valorem, and Other Fees	6,938			10,145			16,130			20,331
Direct Administrative and Selling	13,252			13,503			27,918			25,156
Depreciation, Depletion and Amortization	87,510			71,499			172,614			143,228
Exploration and Production Related Other Costs	2,322			4,624			4,363			7,723
Production Royalty Interests and Purchased Gas Costs	3,635			16,672			19,762			42,768
Other Corporate Expenses	20,551			21,010			39,647			47,174
Impairment of Exploration and Production Properties	828,905			—			828,905			—
General and Administrative	14,431			15,517			29,573			32,881
Total Exploration and Production Costs	1,089,842			237,140			1,361,566			486,456
Coal Costs
Operating and Other Costs	271,284			354,286			582,867			688,096
Royalties and Production Taxes	22,056			27,603			44,373			54,091
Direct Administrative and Selling	8,984			12,130			17,967			23,672
Depreciation, Depletion and Amortization	66,982			65,899			132,465			122,765
Freight Expense	4,251			10,109			10,776			20,054
General and Administrative Costs	6,901			10,657			14,309			23,366
Other Corporate Expenses	13,288			12,037			22,183			31,331
Total Coal Costs	393,746			492,721			824,940			963,375
Other Costs
Miscellaneous Operating Expense	14,052			92,020			24,436			159,361
General and Administrative Costs	—			221			—			431
Depreciation, Depletion and Amortization	5			501			12			1,022
Loss on Debt Extinguishment	17			74,277			67,751			74,277
Interest Expense	46,507			64,211			101,629			115,142
Total Other Costs	60,581			231,230			193,828			350,233
Total Costs And Expenses	1,544,169			961,091			2,380,334			1,800,064
Earnings Before Income Tax	(895,230		)	(23,721		)	(841,803		)	106,459
Income Taxes	(291,929		)	1,214			(317,532		)	9,703
(Loss) Income From Continuing Operations	(603,301		)	(24,935		)	(524,271		)	96,756
Loss From Discontinued Operations, net	—			—			—			(5,687		)
Net (Loss) Income	$	(603,301	)	$	(24,935	)	$	(524,271	)	$	91,069

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(CONTINUED)



	Three Months Ended						Six Months Ended
(Dollars in thousands, except per share data)	June 30,						June 30,
(Unaudited)	2015			2014			2015			2014
Earnings Per Share
Basic
(Loss) Income from Continuing Operations	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.42
Loss from Discontinued Operations	—			—			—			(0.02		)
Total Basic (Loss) Earnings Per Share	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.40
Dilutive
(Loss) Income from Continuing Operations	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.42
Loss from Discontinued Operations	—			—			—			(0.03		)
Total Dilutive (Loss) Earnings Per Share	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.39

Dividends Paid Per Share	$	0.0625		$	0.0625		$	0.125		$	0.125

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended						Six Months Ended
(Dollars in thousands)	June 30,						June 30,
(Unaudited)	2015			2014			2015			2014
Net (Loss) Income	$	(603,301	)	$	(24,935	)	$	(524,271	)	$	91,069
Other Comprehensive Loss:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($4,875), $2,214, ($4,785), ($771))	9,467			(3,798		)	9,318			1,321
Net Decrease in the Value of Cash Flow Hedges (Net of tax: $0, $8,027, $0, $38,883)	—			(12,218		)	—			(59,183		)
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $12,103, ($6,642), $23,316, ($17,593))	(20,804		)	6,951			(40,118		)	23,264

Other Comprehensive Loss	(11,337		)	(9,065		)	(30,800		)	(34,598		)

Comprehensive (Loss) Income	$	(614,638	)	$	(34,000	)	$	(555,071	)	$	56,471

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands)	June 30, 2015		December 31, 2014
ASSETS
Current Assets:
Cash and Cash Equivalents	$	10,031	$	176,989
Accounts and Notes Receivable:
Trade	173,240		259,817
Other Receivables	219,655		347,146
Accounts Receivable - Securitized	38,669		—
Inventories	111,694		101,873
Deferred Income Taxes	74,539		66,569
Recoverable Income Taxes	21,211		20,401
Prepaid Expenses	172,463		193,555
Total Current Assets	821,502		1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	15,344,327		14,674,777
Less—Accumulated Depreciation, Depletion and Amortization	5,624,326		4,512,305
Total Property, Plant and Equipment—Net	9,720,001		10,162,472
Other Assets:
Investment in Affiliates	216,583		152,958
Other	244,015		277,750
Total Other Assets	460,598		430,708
TOTAL ASSETS	$	11,002,101	$	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)	June 30, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	442,153		$	531,973
Current Portion of Long-Term Debt	13,401			13,016
Short-Term Notes Payable	1,058,000			—
Borrowings Under Securitization Facility	38,669			—
Other Accrued Liabilities	543,806			602,972
Total Current Liabilities	2,096,029			1,147,961
Long-Term Debt:
Long-Term Debt	2,558,678			3,236,422
Capital Lease Obligations	38,820			39,456
Total Long-Term Debt	2,597,498			3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	5,119			325,592
Postretirement Benefits Other Than Pensions	635,693			703,680
Pneumoconiosis Benefits	118,288			116,941
Mine Closing	306,231			306,789
Gas Well Closing	181,768			175,369
Workers’ Compensation	75,365			75,947
Salary Retirement	107,233			109,956
Reclamation	34,264			33,788
Other	162,718			158,171
Total Deferred Credits and Other Liabilities	1,626,679			2,006,233
TOTAL LIABILITIES	6,320,206			6,430,072
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,001,412 Issued and Outstanding at June 30, 2015; 230,265,463 Issued and Outstanding at December 31, 2014	2,294			2,306
Capital in Excess of Par Value	2,425,822			2,424,102
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,435,679			3,054,150
Accumulated Other Comprehensive Loss	(181,900		)	(151,100		)
Total CONSOL Energy Inc. Stockholders’ Equity	4,681,895			5,329,458
TOTAL LIABILITIES AND EQUITY	$	11,002,101		$	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
December 31, 2014	$	2,306		$	2,424,102		$	3,054,150		$	(151,100	)	$	5,329,458
(Unaudited)
Net Loss	—			—			(524,271		)	—			(524,271		)
Other Comprehensive Loss	—			—			—			(30,800		)	(30,800		)
Comprehensive Loss	—			—			(524,271		)	(30,800		)	(555,071		)
Issuance of Common Stock	10			8,278			—			—			8,288
Retirement of Common Stock (2,213,100 shares)	(22		)	(17,683		)	(53,969		)	—			(71,674		)
Treasury Stock Activity	—			—			(11,520		)	—			(11,520		)
Tax Cost From Stock-Based Compensation	—			(3,004		)	—			—			(3,004		)
Amortization of Stock-Based Compensation Awards	—			14,129			—			—			14,129
Dividends ($0.125 per share)	—			—			(28,711		)	—			(28,711		)
Balance at June 30, 2015	$	2,294		$	2,425,822		$	2,435,679		$	(181,900	)	$	4,681,895

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



(Dollars in thousands)	Six Months Ended
(Unaudited)	June 30,
Operating Activities:	2015			2014
Net (Loss) Income	$	(524,271	)	$	91,069
Adjustments to Reconcile Net Income to Net Cash Provided By Continuing Operating Activities:
Net Loss from Discontinued Operations	—			5,687
Depreciation, Depletion and Amortization	305,091			267,015
Impairment of Exploration and Production Properties	828,905			—
Stock-Based Compensation	14,129			25,500
Gain on Sale of Assets	(6,480		)	(5,086		)
Loss on Debt Extinguishment	67,751			74,277
Unrealized Gain on Commodity Derivative Instruments	(35,068		)	—
Deferred Income Taxes	(313,114		)	13,785
Equity in Earnings of Affiliates	(23,250		)	(21,512		)
Return on Equity Investment	8,162			—
Changes in Operating Assets:
Accounts and Notes Receivable	90,384			(52,920		)
Inventories	(9,821		)	9,909
Prepaid Expenses	83,560			24,529
Changes in Other Assets	17,188			13,427
Changes in Operating Liabilities:
Accounts Payable	(97,602		)	53,371
Accrued Interest	26,149			(10,483		)
Other Operating Liabilities	(96,978		)	74,714
Changes in Other Liabilities	(46,395		)	9,923
Other	5,875			4,814
Net Cash Provided by Continuing Operations	294,215			578,019
Net Cash Used in Discontinued Operating Activities	—			(20,872		)
Net Cash Provided by Operating Activities	294,215			557,147
Cash Flows from Investing Activities:
Capital Expenditures	(635,785		)	(819,295		)
Proceeds from Sales of Assets	6,931			133,075
Net Investments In Equity Affiliates	(43,761		)	(39,000		)
Net Cash Used in Investing Activities	(672,615		)	(725,220		)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	1,058,000			(11,736		)
Payments on Miscellaneous Borrowings	(4,112		)	(3,167		)
Payments on Long Term Notes, including Redemption Premium	(1,263,719		)	(1,561,937		)
Proceeds from Securitization Facility	38,669			—
Proceeds from Issuance of Long-Term Notes	492,760			1,600,000
Tax Benefit from Stock-Based Compensation	198			2,413
Dividends Paid	(28,711		)	(28,733		)
Issuance of Common Stock	8,288			13,234
Purchases of Treasury Stock	(71,674		)	—
Debt Issuance and Financing Fees	(18,257		)	(22,028		)
Net Cash Provided By (Used in) Financing Activities	211,442			(11,954		)
Net Decrease in Cash and Cash Equivalents	(166,958		)	(180,027		)
Cash and Cash Equivalents at Beginning of Period	176,989			327,420
Cash and Cash Equivalents at End of Period	$	10,031		$	147,393

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 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 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 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, and 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 June 30,		Six Months Ended June 30,
	2015	2014	2015	2014
Anti-Dilutive Options	3,667,080	4,123,949	3,667,080	359,488
Anti-Dilutive Restricted Stock Units	1,606,672	1,265,237	1,606,672	—
Anti-Dilutive Performance Share Units	—	523,357	—	—
Anti-Dilutive Performance Stock Options	802,804	802,804	802,804	—
	6,076,556	6,715,347	6,076,556	359,488

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014
Options	287,592	382,773	363,620	648,112
Restricted Stock Units	37,149	56,403	486,507	390,802
Performance Share Units	—	—	497,134	378,971
	324,741	439,176	1,347,261	1,417,885

The weighted average exercise price per share of the options exercised during the three months ended June 30, 2015 and 2014 was $ 22.78 and $ 21.57 , respectively. The weighted average exercise price per share of the options exercised during the six months ended June 30, 2015 and 2014 was $ 22.78 and $ 20.41 , respectively.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
(Loss) Income from Continuing Operations	$	(603,301	)	$	(24,935	)	$	(524,271	)	$	96,756
Loss from Discontinued Operations	—			—			—			(5,687		)
Net (Loss) Income	$	(603,301	)	$	(24,935	)	$	(524,271	)	$	91,069
Weighted Average Shares of Common Stock Outstanding:
Basic	228,928,803			230,061,395			229,329,382			229,795,193
Effect of Stock-Based Compensation Awards	—			—			—			1,595,988
Dilutive	228,928,803			230,061,395			229,329,382			231,391,181
(Loss) Earnings per Share:
Basic (Continuing Operations)	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.42
Basic (Discontinued Operations)	—			—			—			(0.02		)
Total Basic	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.40

Dilutive (Continuing Operations)	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	0.42
Dilutive (Discontinued Operations)	—			—			—			(0.03		)
Total Dilutive	$	(2.64	)	$	(0.11	)	$	(2.29	)	$	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	—			28,396			28,396
Amounts reclassified from Accumulated Other Comprehensive Income	(40,118		)	(19,078		)	(59,196		)
Current period other comprehensive (loss) income	(40,118		)	9,318			(30,800		)
Balance at June 30, 2015	$	81,403		$	(263,303	)	$	(181,900	)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Derivative Instruments (Note 13)
Natural Gas Price Swaps and Options	$	(32,906	)	$	13,593		$	(63,433	)	$	40,857
Tax Expense (Benefit)	12,102			(6,642		)	23,315			(17,593		)
Net of Tax	$	(20,804	)	$	6,951		$	(40,118	)	$	23,264
Actuarially Determined Long-Term Liability Adjustments (Note 4 and Note 5)
Amortization of Prior Service Costs	$	(54,495	)	$	(2,542	)	$	(69,308	)	$	(5,084	)
Recognized Net Actuarial Loss	24,169			10,861			38,742			21,507
Settlement loss	—			20,707			—			20,707
Total	(30,326		)	29,026			(30,566		)	37,130
Tax Expense (Benefit)	11,398			(10,691		)	11,488			(13,676		)
Net of Tax	$	(18,928	)	$	18,335		$	(19,078	)	$	23,454

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

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 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 six months ended June 30, 2015 , CONSOL Energy made payments to CEVCO totaling $ 15,216 . As of June 30, 2015 , the amount recorded in Other Current Liabilities was $ 35,753 and Other Long-term Liabilities was $ 38,850 . In July 2015, CONSOL Energy made a payment to CEVCO in the amount of $ 35,753 .

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 six months ended June 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				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
Equity in Earnings of Affiliates	$	11,925	$	14,062	$	23,248	$	21,512
Rental Income	9,408		10,697		19,006		25,605
Right of Way Issuance	5,422		513		7,950		2,413
Royalty Income	3,602		4,476		8,147		9,755
Gathering Revenue	2,379		2,020		8,474		20,750
Interest Income	364		676		1,507		1,300
Coal Contract Settlement	—		30,000		—		30,000
Other	2,594		7,533		5,428		13,696
Total Other Income	$	35,694	$	69,977	$	73,760	$	125,031

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 six months ended June 30, 2015 and 2014 are as follows:



	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	2,350		$	4,483		$	4,700		$	8,791		$	—		$	2,331		$	—		$	4,663
Interest cost	8,580			8,993			17,160			18,144			6,889			12,097			13,884			24,194
Expected return on plan assets	(12,690		)	(12,765		)	(25,379		)	(25,512		)	—			—			—			—
Amortization of prior service credits	(176		)	(346		)	(352		)	(692		)	(54,320		)	(2,196		)	(68,956		)	(4,392		)
Recognized net actuarial loss	6,940			6,106			13,880			11,997			18,522			6,369			27,448			12,737
Settlement loss	—			20,707			—			20,707			—			—			—			—
Net periodic cost (benefit)	$	5,004		$	27,178		$	10,009		$	33,435		$	(28,909	)	$	18,601		$	(27,624	)	$	37,202

For the six months ended June 30, 2015 , $ 2,521 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 .

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 six months ended June 30, 2014. Accordingly, CONSOL Energy recognized settlement expense of $20,707 for the three and six months ended June 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 triggered in May 2014, resulting in a remeasurement at May 31, 2014. Additional lump sum distributions during June 2014 resulted in another remeasurement at June 30, 2014. 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.

On May 31, 2015, the Salaried OPEB and Production and Maintenance (P&M) OPEB plans were remeasured to reflect a 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 six months ended June 30, 2015 , $26,935 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 six months ended June 30, 2015 and 2014 are as follows:



	CWP												Workers' Compensation
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	1,623		$	1,418		$	3,246		$	2,837		$	2,347		$	2,445		$	4,695		$	4,890
Interest cost	1,279			1,385			2,558			2,769			799			895			1,597			1,789
Amortization of actuarial gain	(1,394		)	(1,549		)	(2,788		)	(3,098		)	(8		)	(96		)	(15		)	(191		)
State administrative fees and insurance bond premiums	—			—			—			—			973			929			1,876			2,039
Net periodic benefit cost	$	1,508		$	1,254		$	3,016		$	2,508		$	4,111		$	4,173		$	8,153		$	8,527

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 six months ended June 30, 2015 , $5,293 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 six months ended June 30, 2015 , $8,821 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 6—INCOME TAXES:

For the three and six months ended June 30, 2015 , the company recognized an income tax benefit of $291,929 and $ 317,532 respectively. The income tax benefit was primarily driven by impairment charges recorded in June 2015. In addition, as the company's loss for the six months ended June 30, 2015 exceeds the anticipated ordinary loss for the full year, the tax benefit recognized for the six months ended June 30, 2015 was limited to the amount that would be recognized if the year-to-date ordinary loss were the anticipated ordinary loss for the full year. Another item contributing to the benefit is the deduction for percentage depletion in excess of cost depletion related to the company's coal operations.

For the three and six months ended June 30, 2014 the company recognized income tax expense from continuing operations of $1,214 and $ 9,703 , respectively. The Company also recognized an income tax benefit of $1,357 for the six months ended June 30, 2014 related to discontinued operations. 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 six months ended June 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 an income tax benefit of $ (371) 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 six months ended June 30, 2014 the Company recognized a $3,344 income tax expense 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 June 30, 2015 and December 31, 2014 . There were no additions to the liability for unrecognized tax benefits during the six months ended June 30, 2015 .

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. There was no accrued interest on uncertain tax positions for the three or six month periods ended June 30, 2015 . As of December 31, 2014 , the Company had no accrued interest liability relating to uncertain tax positions. The accrued interest liability included $49 and $4,898 of interest income that is reflected in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2014 respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of June 30, 2015 and 2014 , CONSOL Energy had no accrued liability for tax penalties.

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



	June 30, 2015		December 31, 2014
Coal	$	31,168	$	19,242
Supplies	80,526		82,631
Total Inventories	$	111,694	$	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 are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. On March 27, 2015, this facility was amended to allow the Company to receive, on a revolving basis, up to $100,000 of short-term funding and letters of credit. CONSOL Energy may also issue letters of credit against the facility, which decreases the amount available to be drawn upon. The trade accounts receivable facility was terminated on July 7, 2015.

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

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

At June 30, 2015 and December 31, 2014 , eligible accounts receivable totaled $89,400 and $77,800 , respectively. Outstanding letters of credit were $49,431 at June 30, 2015 compared to $60,230 , at December 31, 2014 . There were outstanding borrowings of $38,669 at June 30, 2015 and no outstanding borrowings at December 31, 2014 .

After taking into account outstanding letters of credit and outstanding borrowings, there remained $1,300 and $17,570 in subordinated retained interest at June 30, 2015 and December 31, 2014 , respectively. These changes are reflected in the Net Cash Used in Financing Activities section of the Consolidated Statement of Cash Flows. CONSOL Energy's management believes that the letters of credit will expire without being funded, and therefore, the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

The cost of funds under this facility is based upon commercial paper rates or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $ 207 and $484 for the three months ended June 30, 2015 and 2014 and $403 and $484 for the six months ended June 30, 2015 and 2014. These costs have been recorded as financing fees which are included in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. No servicing asset or liability has been recorded at June 30, 2015 .

NOTE 9—PROPERTY, PLANT AND EQUIPMENT:



	June 30, 2015		December 31, 2014
E&P Property, Plant, and Equipment
Intangible drilling cost	$	3,252,037	$	2,798,394
Proven gas properties	1,770,034		1,768,007
Unproven gas properties	1,570,720		1,540,835
Gas gathering equipment	1,113,736		1,088,238
Gas wells and related equipment	802,441		716,748
Other gas assets	125,112		123,539
Gas advance royalties	19,908		20,580
Total E&P Property, Plant, and Equipment	$	8,653,988	$	8,056,341
Less: Accumulated Depreciation, Depletion and Amortization	2,512,651		1,523,761
Total E&P Property, Plant, and Equipment - Net	$	6,141,337	$	6,532,580

Coal and Other Property, Plant and Equipment:
Coal and other plant and equipment	$	3,793,530	$	3,726,514
Coal properties and surface lands	1,360,175		1,358,306
Airshafts	470,227		468,924
Mine development	412,081		414,501
Coal advance mining royalties	390,274		386,245
Leased coal lands	264,052		263,946
Total Coal and Other Property, Plant, and Equipment	$	6,690,339	$	6,618,436
Less: Accumulated Depreciation, Depletion and Amortization	3,111,675		2,988,544
Total Coal and Corporate Property, Plant and Equipment- Net	$	3,578,664	$	3,629,892

Total Company Property, Plant, and Equipment	$	15,344,327	$	14,674,777
Less - Total Company Accumulated Depreciation, Depletion, and Amortization	5,624,326		4,512,305
Total Company Property, Plant and Equipment - Net	$	9,720,001	$	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.

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. The impaired assets now have approximately $ 165,900 of carrying value remaining. If gas prices continue to decrease later in 2015, another impairment of these assets, or other natural gas assets, is possible.

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 153,000 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 June 30, 2015 , Hess’ remaining carry obligation is $ 52,075 . For the six months ended June 30, 2015 and June 30, 2014, Hess' carry payments to CNX Gas Company reduced capital expenditures by $ 47,851 and $ 29,984 , respectively.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 702,000 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 June 30, 2015 , Noble Energy’s remaining carry obligation is $1,624,448 . For the six months ended June 30, 2015 and June 30, 2014 , Noble's carry payments to CNX Gas Company reduced capital expenditures by $ 25,578 and $ 25,607 , 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 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 and accounts receivable securitization facility, measured quarterly. At June 30, 2015 , the interest coverage ratio was 4.65 to 1.00 and the current ratio was 1.38 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.

At June 30, 2015 , the $2,000,000 facility had $ 1,058,000 of borrowings outstanding and $ 237,463 of letters of credit outstanding, leaving $ 704,537 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.

On March 9, 2015, Consol Pennsylvania Coal Company LLC (CPCC) and Conrhein Coal Company (Conrhein) which are wholly owned subsidiaries of the Company, entered into a $600,000 commitment for a senior secured term loan facility. The facility is secured by the thermal coal assets related to CONSOL Energy’s existing Pennsylvania operations along with CONSOL Energy providing a guarantee to the lenders and a pledge of its equity interests in CPCC and Conrhein. The term loan commitment expired on the closing of the CNX Coal Resources LP initial public offering, which was effective on July 7, 2015. CONSOL Energy has recorded $ 4,500 within the Other Receivables line item of the Consolidated Balance Sheets as of June 30, 2015 for financing fees that are refundable to the Company.

NOTE 11—LONG-TERM DEBT:



	June 30, 2015		December 31, 2014
Debt:

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
Senior notes due April 2022 at 5.875%, including amortization of bond premium	1,856,062		1,856,506
Senior notes due April 2023 at 8.00%, including amortization of bond discount	492,986		—
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.91% weighted average interest rate for June 30, 2015 and December 31, 2014)	13,473		13,473
Other long-term note maturing in 2018 (total value of $3,784 and $4,473 less unamortized discount of $473 and $643 at June 30, 2015 and December 31, 2014, respectively).	3,311		3,830
	2,563,778		3,241,474
Less amounts due in one year *	5,100		5,052
Long-Term Debt	$	2,558,678	$	3,236,422

* Excludes current portion of Capital Lease Obligations of $8,301 and $ 7,964 at June 30, 2015 and December 31, 2014 , respectively.

Accrued interest related to Long-Term Debt of $ 37,108 and $ 51,159 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 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 Statement 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 Statement of Income.

On April 16, 2014 CONSOL Energy purchased all the 8.00% senior notes that were due 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 Statement of Income.

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 $539,196 .

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 has set aside September 8 - 10, 2015 for a class certification hearing. 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 has set aside September 8 - 10, 2015 for a class certification hearing. 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 was 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. The investigation has focused primarily on exceedances at three discharge points: Pond 12, Pond 2 and Pond 13. 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 was 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 are being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.

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. The Company intends to vigorously defend these 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 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 June 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	$	95,026	$	40,359	$	54,667	$	—	$	—
Environmental	4,786		3,058		1,728		—		—
Other	187,082		151,185		35,897		—		—
Total Letters of Credit	286,894		194,602		92,292		—		—
Surety Bonds:
Employee-Related	115,199		115,199		—		—		—
Environmental	547,782		546,876		906		—		—
Other	24,578		24,404		173		—		1
Total Surety Bonds	687,559		686,479		1,079		—		1
Guarantees:
Coal	83,500		66,800		16,700		—		—
Other	80,914		41,604		15,871		12,562		10,877
Total Guarantees	164,414		108,404		32,571		12,562		10,877
Total Commitments	$	1,138,867	$	989,485	$	125,942	$	12,562	$	10,878

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 June 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 June 30, 2015 , the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	225,158
1 - 3 years	295,495
3 - 5 years	192,339
More than 5 years	604,418
Total Purchase Obligations	$	1,317,410

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 Other Comprehensive Income (OCI) will be immediately recorded in earnings. In November 2014, CONSOL Energy entered into basis only swaps that did not qualify for hedge accounting. These swaps were entered into to decrease the risk related to pricing differentials between local markets and NYMEX.

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

None of 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 hedges 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.

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 220.0 bcf at June 30, 2015 and are forecasted to settle through 2017. At December 31, 2014 , the commodity derivative instruments accounted for a total notional amount of production of 215.9 Bcf. At June 30, 2015 , the basis only swaps were for notional amounts of 6.8 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 June 30, 2015 and December 31, 2014 were as follows:



Asset Derivative Instruments					Liability Derivative Instruments
	June 30,		December 31,			June 30,		December 31,
	2015		2014			2015		2014
Commodity Derivative Instruments
Prepaid Expense	$	117,002	$	123,676	Other Liabilities	$	2,359	$	—
Other Assets	49,899		68,656		Other Accrued Liabilities	1,342		—
Total Asset:	$	166,901	$	192,332	Total Liability	$	3,701	$	—

Basis Only Swaps
Prepaid Expense	$	2,770	$	1,064	Other Accrued Liabilities	$	1,267	$	327

The commodity derivative instruments resulted in a loss of $27,370 being recorded in Unrealized (Loss) Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the three months ended June 30, 2015 . No gain or loss was recorded for the three months ended June 30, 2014 . A gain of $34,261 was recorded to Unrealized (Loss) Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the six months ended June 30, 2015 . No gain or loss was recorded for the six months ended June 30, 2014 .

The basis only swaps resulted in a gain of $2,434 being recorded in Unrealized (Loss) Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the three months ended June 30, 2015 . No gain or loss was recorded for the three months ended June 30, 2014 . A gain of $807 was recorded to Unrealized (Loss) Gain on Commodity Derivative Instruments on the Consolidated Statements of Income for the six months ended June 30, 2015 . No gain or loss was recorded for the six months ended June 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, as follows:



	Three Months Ended June 30,
	2015			2014
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	102,207		$	11,841
Gain/(Loss) recognized in Accumulated OCI	—			(12,218		)
Amounts reclassified from Accumulated OCI (Net of tax: $12,103, ($6,642))	(20,804		)	6,951
Ending Balance – Accumulated OCI	$	81,403		$	6,574
Gain recognized in Outside Sales for ineffectiveness *	$	—		$	508

	Six Months Ended June 30,
	2015			2014
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	121,521		$	42,493
Gain/(Loss) recognized in Accumulated OCI	—			(59,183		)
Amounts reclassified from Accumulated OCI (Net of tax: $23,316, ($17,593))	(40,118		)	23,264
Ending Balance – Accumulated OCI	$	81,403		$	6,574
Gain recognized in Outside Sales for ineffectiveness *	$	—		$	863

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

CONSOL Energy expects to reclassify an additional $37,934 , net of tax of $21,738 , 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 June 30, 2015						Fair Value Measurements at December 31, 2014
Description	(Level 1)		(Level 2)		(Level 3)		(Level 1)		(Level 2)		(Level 3)
Gas Derivatives	$	—	$	164,703	$	—	$	—	$	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.

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

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

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



	June 30, 2015						December 31, 2014
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	10,031		$	10,031		$	176,989		$	176,989
Short-Term Notes Payable	$	(1,058,000	)	$	(1,058,000	)	$	—		$	—
Borrowings Under Securitization Facility	$	(38,669	)	$	(38,669	)	$	—		$	—
Long-Term Debt	$	(2,563,778	)	$	(2,263,935	)	$	(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 six months ended June 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 six months ended June 30, 2015 , the VA Operations aggregated segment includes the Buchanan Mine and the corresponding preparation plant facilities. For the three and six months ended June 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 June 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	$	97,697		$	17,661		$	65,393	$	21,160		$	201,911		$	318,995	$	63,316	$	32,169		$	414,480	$	—		$	—		$	616,391		(A)
Other outside sales	—			—			—		—			—			—		—		6,337			6,337		—			—			6,337
Sales—purchased gas	—			—			—		1,517			1,517			—		—		—			—		—			—			1,517
Sales—production royalty interests	—			—			—		5,370			5,370			—		—		—			—		—			—			5,370
Freight—outside	—			—			—		—			—			2,706		228		1,317			4,251		—			—			4,251
Intersegment transfers	—			—			349		—			349			—		—		—			—		—			(349		)	—
Total Sales and Freight	$	97,697		$	17,661		$	65,742	$	28,047		$	209,147		$	321,701	$	63,544	$	39,823		$	425,068	$	—		$	(349	)	$	633,866
Earnings (Loss) Before Income Taxes	$	(6,979	)	$	(6,910	)	$	9,710	$	(887,193	)	$	(891,372	)	$	61,804	$	7,563	$	(14,489	)	$	54,878	$	(1,028	)	$	(57,708	)	$	(895,230	)	(B)
Segment assets												$	6,761,700		$	2,090,674	$	355,112	$	1,578,267		$	4,024,053	$	79,531		$	136,817		$	11,002,101		(C)
Depreciation, depletion and amortization												$	87,510		$	46,473	$	11,622	$	8,887		$	66,982	$	5		$	—		$	154,497
Capital expenditures												$	289,152		$	35,473	$	10,180	$	2,707		$	48,360	$	4,254		$	—		$	341,766

(A) Included in the Coal segment are sales of $86,024 to Xcoal Energy & Resources and sales of $ 80,433 to Duke Energy, each comprising over 10% of sales.

(B) Includes equity in earnings of unconsolidated affiliates of $10,033 and $1,894 for E&P and Coal, respectively.

Industry segment results for the three months ended June 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	$	104,584	$	13,505	$	80,681	$	30,973		$	229,743	$	434,944	$	67,265		$	34,089		$	536,298	$	—		$	—		$	766,041		(D)
Other outside sales	—		—		—		—			—		—		—			10,027			10,027		60,060			—			70,087
Sales—purchased gas	—		—		—		1,404			1,404		—		—			—			—		—			—			1,404
Sales—production royalty interests	—		—		—		18,335			18,335		—		—			—			—		—			—			18,335
Freight—outside	—		—		—		—			—		6,722		154			3,233			10,109		—			—			10,109
Intersegment transfers	—		—		555		—			555		—		—			—			—		20,035			(20,590		)	—
Total Sales and Freight	$	104,584	$	13,505	$	81,236	$	50,712		$	250,037	$	441,666	$	67,419		$	47,349		$	556,434	$	80,095		$	(20,590	)	$	865,976
Earnings (Loss) Before Income Taxes	$	34,764	$	4,727	$	17,949	$	(34,106	)	$	23,334	$	132,279	$	(1,141	)	$	(10,023	)	$	121,115	$	(1,159	)	$	(167,011	)	$	(23,721	)	(E)
Segment assets										$	6,797,166	$	2,101,765	$	369,785		$	1,740,781		$	4,212,331	$	195,417		$	361,733		$	11,566,647		(F)
Depreciation, depletion and amortization										$	71,499	$	44,638	$	11,670		$	9,591		$	65,899	$	501		$	—		$	137,899
Capital expenditures										$	304,486	$	54,868	$	5,103		$	2,286		$	62,257	$	1,543		$	—		$	368,286


(D)	Included in the Coal segment are sales of $104,919 to Duke Energy, which comprises over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $6,996 and $7,066 for E&P and Coal, respectively.

(F) Includes investments in unconsolidated equity affiliates of $259,870 , $91,930 and $ 387 for E&P, Coal and All Other, respectively.

Industry segment results for the six months ended June 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	$	235,057	$	36,264		$	140,377	$	44,793		$	456,491		$	703,432	$	143,831	$	63,883		$	911,146	$	—		$	—		$	1,367,637		(G)
Other outside sales	—		—			—		—			—			—		—		19,467			19,467		—			—			19,467
Sales—purchased gas	—		—			—		5,114			5,114			—		—		—			—		—			—			5,114
Sales—production royalty interests	—		—			—		20,229			20,229			—		—		—			—		—			—			20,229
Freight—outside	—		—			—		—			—			5,075		228		5,473			10,776		—			—			10,776
Intersegment transfers	—		—			896		—			896			—		—		—			—		—			(896		)	—
Total Sales and Freight	$	235,057	$	36,264		$	141,273	$	70,136		$	482,730		$	708,507	$	144,059	$	88,823		$	941,389	$	—		$	(896	)	$	1,423,223
Earnings (Loss) Before Income Taxes	$	35,265	$	(11,963	)	$	24,442	$	(863,125	)	$	(815,381	)	$	160,205	$	30,130	$	(29,575	)	$	160,760	$	(926	)	$	(186,256	)	$	(841,803	)	(H)
Segment assets											$	6,761,700		$	2,090,674	$	355,112	$	1,578,267		$	4,024,053	$	79,531		$	136,817		$	11,002,101		(I)
Depreciation, depletion and amortization											$	172,614		$	91,323	$	23,597	$	17,545		$	132,465	$	12		$	—		$	305,091
Capital expenditures											$	539,455		$	68,395	$	16,415	$	4,392		$	89,202	$	7,128		$	—		$	635,785

(G) Included in the Coal segment are sales of $208,269 to Xcoal Energy & Resources and sales of $ 165,049 to Duke Energy, each comprising over 10% of sales.

(H) Includes equity in earnings of unconsolidated affiliates of $18,410 and $4,840 for E&P and Coal, respectively.

(I) Includes investments in unconsolidated equity affiliates of $181,106 and $35,477 for E&P and Coal, respectively.

Industry segment results for the six months ended June 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	$	229,541	$	20,536	$	176,752	$	69,212		$	496,041	$	847,025	$	151,770		$	72,184		$	1,070,979	$	—		$	—		$	1,567,020	(J)
Other outside sales	—		—		—		—			—		—		—			20,510			20,510		118,864			—			139,374
Sales—purchased gas	—		—		—		4,978			4,978		—		—			—			—		—			—			4,978
Sales—production royalty interests	—		—		—		44,980			44,980		—		—			—			—		—			—			44,980
Freight—outside	—		—		—		—			—		14,152		512			5,390			20,054		—			—			20,054
Intersegment transfers	—		—		1,452		—			1,452		—		—			—			—		39,346			(40,798		)	—
Total Sales and Freight	$	229,541	$	20,536	$	178,204	$	119,170		$	547,451	$	861,177	$	152,282		$	98,084		$	1,111,543	$	158,210		$	(40,798	)	$	1,776,406
Earnings (Loss) Before Income Taxes	$	93,869	$	5,266	$	51,568	$	(49,784	)	$	100,919	$	265,069	$	(770	)	$	(31,532	)	$	232,767	$	(2,897	)	$	(224,330	)	$	106,459	(K)
Segment assets										$	6,797,166	$	2,101,765	$	369,785		$	1,740,781		$	4,212,331	$	195,417		$	361,733		$	11,566,647	(L)
Depreciation, depletion and amortization										$	143,228	$	79,800	$	23,382		$	19,583		$	122,765	$	1,022		$	—		$	267,015
Capital expenditures										$	570,456	$	229,048	$	11,345		$	5,927		$	246,320	$	2,519		$	—		$	819,295


(J)	Included in the Coal segment are sales of $189,921 to Duke Energy and sales of $188,491 to Xcoal Energy & Resources, each comprising over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $12,810 , $10,065 and $(1,363) for E&P, Coal and All Other, respectively.

(L) Includes investments in unconsolidated equity affiliates of $259,870 , $91,930 and $387 for E&P, Coal and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
Segment Earnings Before Income Taxes for total reportable business segments	$	(836,494	)	$	144,449		$	(654,621	)	$	333,686
Segment Earnings Before Income Taxes for all other businesses	(1,028		)	(1,159		)	(926		)	(2,897		)
Interest (expense), net (M)	(46,507		)	(64,211		)	(101,629		)	(115,142		)
Other corporate items (M)	(11,184		)	(28,523		)	(16,876		)	(34,911		)
Loss on debt extinguishment	(17		)	(74,277		)	(67,751		)	(74,277		)
(Loss) Earnings Before Income Taxes	$	(895,230	)	$	(23,721	)	$	(841,803	)	$	106,459



Total Assets:	June 30,
Total Assets:	2015		2014
Segment assets for total reportable business segments	$	10,785,753	$	11,009,497
Segment assets for all other businesses	79,531		195,417
Items excluded from segment assets:
Cash and other investments (M)	9,946		136,266
Recoverable income taxes	21,211		47,060
Deferred tax assets	74,539		137,716
Bond issuance costs	31,121		40,691
Total Consolidated Assets	$	11,002,101	$	11,566,647

_________________________

(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 $1,856,062 , 5.875% per annum senior notes due April 15, 2022 , and the $492,986 , 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 substantially all subsidiaries of CONSOL Energy. In December 2014, the Company completed the sale of its industrial supplies subsidiary, which constituted the only significant non-guarantor subsidiary. Subsequent to this sale, the Parent Issuer does not have independent assets or operations and the remaining non-guarantor subsidiaries are minor. As a result, condensed consolidating financial statements are not required for the periods subsequent to December 31, 2014. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries for the periods prior to January 1, 2015. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

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



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	230,299	$	—		$	—	$	(556	)	$	229,743
Coal Sales	—			—		536,298			—		—			536,298
Other Outside Sales	—			—		10,027			60,060		—			70,087
Production Royalty Interests and Purchased Gas Sales	—			19,739		—			—		—			19,739
Freight-Outside Coal	—			—		10,109			—		—			10,109
Miscellaneous Other Income	84,216			9,671		57,424			2,740		(84,074		)	69,977
Gain (Loss) on Sale of Assets	—			2,920		(1,505		)	2		—			1,417
Total Revenue and Other Income	84,216			262,629		612,353			62,802		(84,630		)	937,370
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			26,374		—			—		—			26,374
Transportation, Gathering and Compression	—			57,796		—			—		—			57,796
Production, Ad Valorem, and Other Fees	—			10,145		—			—		—			10,145
Direct Administrative and Selling	—			13,503		—			—		—			13,503
Depreciation, Depletion and Amortization	—			71,499		—			—		—			71,499
Exploration and Production Related Other Costs	—			4,624		—			—		—			4,624
Production Royalty Interests and Purchased Gas Costs	—			16,672		—			—		—			16,672
Other Corporate Expenses	—			21,010		—			—		—			21,010
General and Administrative	—			15,517		—			—		—			15,517
Total Exploration and Production Costs	—			237,140		—			—		—			237,140
Coal Costs
Operating and Other Costs	5,571			—		349,271			—		(556		)	354,286
Royalties and Production Taxes	—			—		27,603			—		—			27,603
Direct Administrative and Selling	—			—		12,130			—		—			12,130
Depreciation, Depletion and Amortization	157			—		65,742			—		—			65,899
Freight Expense	—			—		10,109			—		—			10,109
General and Administrative Costs	—			—		10,657			—		—			10,657
Other Corporate Expenses	—			—		12,037			—					12,037
Total Coal Costs	5,728			—		487,549			—		(556		)	492,721
Other Costs
Miscellaneous Operating Expense	32,553			—		741			59,870		(1,144		)	92,020
General and Administrative Costs	—			—		(210		)	431		—			221
Depreciation, Depletion and Amortization	7			—		4			490		—			501
Loss on Debt Extinguishment	74,277			—		—			—		—			74,277
Interest Expense	61,389			2,155		1,948			41		(1,322		)	64,211
Total Other Costs	168,226			2,155		2,483			60,832		(2,466		)	231,230
Total Costs And Expenses	173,954			239,295		490,032			60,832		(3,022		)	961,091
(Loss) Earnings Before Income Tax	(89,738		)	23,334		122,321			1,970		(81,608		)	(23,721		)
Income Taxes	(64,803		)	7,833		57,438			746		—			1,214
Net (Loss) Income	$	(24,935	)	$	15,501	$	64,883		$	1,224	$	(81,608	)	$	(24,935	)

Balance Sheet at December 31, 2014 :



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	145,239		$	30,682		$	—		$	1,068		$	—		$	176,989
Accounts and Notes Receivable:
Trade	—			117,912			—			141,905			—			259,817
Other Receivables	25,497			309,247			12,390			12			—			347,146
Inventories	—			14,748			87,125			—			—			101,873
Recoverable Income Taxes	79,426			(59,025		)	—			—			—			20,401
Deferred Income Taxes	99,776			(33,207		)	—			—			—			66,569
Prepaid Expenses	38,418			129,796			25,341			—			—			193,555
Total Current Assets	388,356			510,153			124,856			142,985			—			1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	158,555			8,066,308			6,449,914			—			—			14,674,777
Less-Accumulated Depreciation, Depletion and Amortization	108,432			1,497,569			2,906,304			—			—			4,512,305
Total Property, Plant and Equipment-Net	50,123			6,568,739			3,543,610			—			—			10,162,472
Other Assets:
Investment in Affiliates	12,571,886			121,721			27,544			—			(12,568,193		)	152,958
Other	172,884			71,339			33,527			—			—			277,750
Total Other Assets	12,744,770			193,060			61,071			—			(12,568,193		)	430,708
Total Assets	$	13,183,249		$	7,271,952		$	3,729,537		$	142,985		$	(12,568,193	)	$	11,759,530
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	86,313		$	385,381		$	60,279		$	—		$	—		$	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			3,929			—			—			13,016
Short-Term Notes Payable	—			720,150			—			—			(720,150		)	—
Other Accrued Liabilities	119,484			172,787			310,701			—			—			602,972
Total Current Liabilities	4,707,456			1,467,678			(4,958,300		)	(68,873		)	—			1,147,961
Long-Term Debt:	3,124,129			37,342			114,407			—			—			3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(148,925		)	474,517			—			—			—			325,592
Postretirement Benefits Other Than Pensions	—			—			703,680			—			—			703,680
Pneumoconiosis Benefits	—			—			116,941			—			—			116,941
Mine Closing	—			—			306,789			—			—			306,789
Gas Well Closing	—			116,930			58,439			—			—			175,369
Workers’ Compensation	—			—			75,947			—			—			75,947
Salary Retirement	109,956			—			—			—			—			109,956
Reclamation	—			—			33,788			—			—			33,788
Other	61,175			94,378			2,618			—			—			158,171
Total Deferred Credits and Other Liabilities	22,206			685,825			1,298,202			—			—			2,006,233
Total CONSOL Energy Inc. Stockholders’ Equity	5,329,458			5,081,107			7,275,228			211,858			(12,568,193		)	5,329,458
Total Liabilities and Equity	$	13,183,249		$	7,271,952		$	3,729,537		$	142,985		$	(12,568,193	)	$	11,759,530

Income Statement for the Six Months Ended June 30, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	497,493	$	—		$	—		$	(1,452	)	$	496,041
Coal Sales	—			—		1,070,979			—			—			1,070,979
Other Outside Sales	—			—		20,510			118,864			—			139,374
Production Royalty Interests and Purchased Gas Sales	—			49,958		—			—			—			49,958
Freight-Outside Coal	—			—		20,054			—			—			20,054
Miscellaneous Other Income	241,788			37,828		81,799			5,042			(241,426		)	125,031
Gain (Loss) on Sale of Assets	—			6,072		(991		)	5			—			5,086
Total Revenue and Other Income	241,788			591,351		1,192,351			123,911			(242,878		)	1,906,523
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			55,617		—			—			—			55,617
Transportation, Gathering and Compression	—			111,578		—			—			—			111,578
Production, Ad Valorem, and Other Fees	—			20,331		—			—			—			20,331
Direct Administrative and Selling	—			25,156		—			—			—			25,156
Depreciation, Depletion and Amortization	—			143,228		—			—			—			143,228
Exploration and Production Related Other Costs	—			7,723		—			—			—			7,723
Production Royalty Interests and Purchased Gas Costs	—			42,780		—			—			(12		)	42,768
Other Corporate Expenses	—			47,174		—			—			—			47,174
General and Administrative	—			32,881		—			—			—			32,881
Total Exploration and Production Costs	—			486,468		—			—			(12		)	486,456
Coal Costs
Operating and Other Costs	16,602			—		672,946			—			(1,452		)	688,096
Royalties and Production Taxes	—			—		54,091			—			—			54,091
Direct Administrative and Selling	—			—		23,672			—			—			23,672
Depreciation, Depletion and Amortization	313			—		122,452			—			—			122,765
Freight Expense	—			—		20,054			—			—			20,054
General and Administrative Costs	—			—		23,366			—			—			23,366
Other Corporate Expenses	—			—		31,331			—			—			31,331
Total Coal Costs	16,915			—		947,912			—			(1,452		)	963,375
Other Costs
Miscellaneous Operating Expense	39,789			—		1,031			118,541			—			159,361
General and Administrative Costs	—			—		—			431			—			431
Depreciation, Depletion and Amortization	13			—		46			963			—			1,022
Loss on Debt Extinguishment	74,277			—		—			—			—			74,277
Interest Expense	109,822			3,964		3,542			94			(2,280		)	115,142
Total Other Costs	223,901			3,964		4,619			120,029			(2,280		)	350,233
Total Costs And Expenses	240,816			490,432		952,531			120,029			(3,744		)	1,800,064
Earnings (Loss) Before Income Tax	972			100,919		239,820			3,882			(239,134		)	106,459
Income Taxes	(90,097		)	38,547		59,784			1,469			—			9,703
Income (Loss) From Continuing Operations	91,069			62,372		180,036			2,413			(239,134		)	96,756
Loss From Discontinued Operations, net	—			—		—			(5,687		)	—			(5,687		)
Net Income (Loss)	$	91,069		$	62,372	$	180,036		$	(3,274	)	$	(239,134	)	$	91,069

Cash Flow for the Six Months Ended June 30, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash (Used in) Provided by Continuing Operations	$	(159,864	)	$	305,113		$	148,731		$	21,426		$	262,613		$	578,019
Net Cash Used In Discontinued Operating Activities	—			—			—			(20,872		)	—			(20,872		)
Net Cash (Used in) Provided by Operating Activities	$	(159,864	)	$	305,113		$	148,731		$	554		$	262,613		$	557,147
Cash Flows from Investing Activities:
Capital Expenditures	$	(1,139	)	$	(570,456	)	$	(247,700	)	$	—		$	—		$	(819,295	)
Proceeds From Sales of Assets	(13,627		)	52,432			94,265			5			—			133,075
(Investments in), net of Distributions from, Equity Affiliates	—			(41,000		)	2,000			—			—			(39,000		)
Net Cash (Used in) Provided by Continuing Operations	$	(14,766	)	$	(559,024	)	$	(151,435	)	$	5		$	—		$	(725,220	)
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	$	(11,736	)	$	262,613		$	—		$	—		$	(262,613	)	$	(11,736	)
Payments on Miscellaneous Borrowings	(2,493		)	—			(252		)	(422		)	—			(3,167		)
Proceeds from Long-Term Borrowings	1,600,000			—			—			—			—			1,600,000
Payments on Long-Term Borrowings	(1,561,937		)	—			—			—			—			(1,561,937		)
Tax Benefit from Stock-Based Compensation	2,413			—			—			—			—			2,413
Dividends Paid	(28,733		)	—			—			—			—			(28,733		)
Proceeds from Issuance of Common Stock	13,234			—			—			—			—			13,234
Other Financing Activities	(22,028		)	(2,956		)	2,956			—			—			(22,028		)
Net Cash (Used in) Provided by Continuing Operations	$	(11,280	)	$	259,657		$	2,704		$	(422	)	$	(262,613	)	$	(11,954	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(24,935	)	$	15,501		$	64,883		$	1,224	$	(81,608	)	$	(24,935	)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	(3,798		)	—			(3,798		)	—		3,798			(3,798		)
Net (Decrease) Increase in the Value of Cash Flow Hedge	(12,218		)	(12,218		)	—			—		12,218			(12,218		)
Reclassification of Cash Flow Hedge from OCI to Earnings	6,951			6,951			—			—		(6,951		)	6,951
Other Comprehensive (Loss) Income:	(9,065		)	(5,267		)	(3,798		)	—		9,065			(9,065		)
Comprehensive (Loss) Income	$	(34,000	)	$	10,234		$	61,085		$	1,224	$	(72,543	)	$	(34,000	)

Statement of Comprehensive Income for the Six Months Ended June 30, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	91,069		$	62,372		$	180,036	$	(3,274	)	$	(239,134	)	$	91,069
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	1,321			—			1,321		—			(1,321		)	1,321
Net (Decrease) Increase in the Value of Cash Flow Hedge	(59,183		)	(59,183		)	—		—			59,183			(59,183		)
Reclassification of Cash Flow Hedge from OCI to Earnings	23,264			23,264			—		—			(23,264		)	23,264
Other Comprehensive (Loss) Income:	(34,598		)	(35,919		)	1,321		—			34,598			(34,598		)
Comprehensive Income (Loss)	$	56,471		$	26,453		$	181,357	$	(3,274	)	$	(204,536	)	$	56,471

NOTE 17—RELATED PARTY TRANSACTIONS:

On September 30, 2011, CNX Gas Company and Noble Energy, Inc., an unrelated third party and joint venture partner, formed CONE Gathering LLC 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.

During the six months ended June 30, 2015 there was $ 8,387 of additional capital contributions to CONE Gathering, LLC and $ 42,750 to CONE Midstream Partners, LP (the Partnership). The capital contributions were offset, in part, by $ 8,162 of distributions from CONE Midstream Partners, LP. During the six months ended June 30, 2014 there was $ 43,000 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 June 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 June 30, 2015 and 2014 related to CONE Gathering LLC was $4,538 and $6,823 , respectively. Equity in earnings of affiliates related to CONE Midstream Partners, LP was $4,843 during the three months ended June 30, 2015. For the six months ended June 30, 2015 and 2014, equity in earnings of affiliates related to CONE Gathering LLC was $ 7,676 and $ 11,224 , respectively. For the six months ended June 30, 2015, equity in earnings of affiliates related to CONE Midstream Partners, LP was $ 9,361 .

During the six months ended June 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 $24,926 and $14,382 for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, gathering services were $47,286 and $26,207 , respectively. These costs were included in Exploration and Production Costs - Transportation, Gathering and Compression on CONSOL Energy’s accompanying Consolidated Statements

of Income. At June 30, 2015 and December 31, 2014, CONSOL Energy had a net payable of $10,806 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 six months ended June 30, 2015 , CONSOL Energy purchased no supply inventory and $ 2,239 of supply inventory from the Partnership, respectively.

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 June 30, 2015, no shares were repurchased. During the six months ended June 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 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 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 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 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 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 EVENT:

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 has agreed to purchase, and CNXC has 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.

Also in connection with the IPO offering, the Partnership entered into a new $400,000 senior secured revolving credit facility with certain lenders and PNC Bank, National Association, as administrative agent (“PNC”). Obligations under the new revolving credit facility will be guaranteed by certain of the Partnerships subsidiaries (the“guarantor subsidiaries”) and will be secured by substantially all of the Partnerships and the Partnerships subsidiaries’ assets pursuant to a security agreement and various mortgages. In connection with the new revolving credit facility, the Partnership 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 $342,777 .


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

General

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 changes in projected capital spending served as impairment indicators 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 $824.7 million, of which approximately 95% related to the Company’s shallow oil and gas assets in West Virginia and Pennsylvania. If gas prices continue to decrease later in 2015, another impairment of these assets, or other natural gas assets, is possible in the near future. Also during the quarter, CONSOL Energy recorded unproven property impairments of $4.2 million relating to the determination that the properties will not yield proven reserves. This impairment primarily relates to the court ruling in June 2015 in the state of New York that officially bans hydraulic fracturing.

During the second quarter, CONSOL Energy entered into ethane, propane, and butane sales agreements to ship volumes via Mariner East pipelines to the Marcus Hook Industrial Complex, which will ultimately export the volumes to Europe. The deals, which commence late next year, are expected to yield price premiums compared with in-basin pricing and expose a portion of the company’s liquefied petroleum gas (LPG) portfolio to Brent Crude pricing.

For the second quarter of 2015, CONSOL Energy's average sales price for natural gas, natural gas liquids, oil, and condensate was $2.68 per Mcfe. CONSOL Energy's average price for natural gas was $2.03 per Mcf for the quarter and, including hedging, was $2.67 per Mcf. During the second quarter, CONSOL Energy produced NGL, oil, and condensate volumes of 9.1 Bcfe, or 12% of the company's total gas equivalent volumes. These liquids volumes were over three times greater than the year-earlier quarter, which then comprised 5% of the company's total gas equivalent volumes. The average realized price for all liquids for the second quarter of 2015 was $16.52 per barrel. Across all volumes, the sale of liquids provided a sales value uplift of $0.09 per Mcfe, excluding hedging, during the 2015 second quarter.

The company currently has a total of 1.1 Bcf per day of available firm transportation capacity. This is composed of 0.8 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 1.8 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.

Also during the quarter, CONSOL Energy took another step towards creating more transparency by successfully executing a thermal coal MLP initial public offering (IPO). The thermal coal MLP, known as CNX Coal Resources LP ("CNXC"), raised approximately $343 million of net proceeds, including the assignment of approximately $200 million in debt. The company used the proceeds to pay down CONSOL Energy's parent credit facility in July since the transaction officially closed after the second quarter ended. In connection with the completion of the IPO of CNX Coal Resources LP, CONSOL Energy granted CNXC a right of first offer to acquire its retained 80% undivided interest in the Pennsylvania mining complex along with the following three assets: the Baltimore Marine Terminal, Cardinal States Gathering System, and the Buchanan Mine.

Due to the continued degradation of metallurgical coal prices, CONSOL Energy is putting the MetCo IPO on hold, which was previously announced to occur early in the fourth quarter of 2015. In addition to evaluating this asset as a potential future drop down into CNXC, CONSOL Energy is also evaluating the possibility of partnering with a third party to grow this asset through consolidation, before a potential future initial public offering. Both options support CONSOL Energy's strategic and structural goals, and the company expects to make a decision regarding its Buchanan Mine asset by year-end 2015.

CONSOL Energy’s Pennsylvania Operations had another solid quarter selling 5.7 million tons to 38 different end users. During the quarter, CONSOL Energy contracted for 0.1 million additional tons for 2015, bringing the total firm and priced contracted position to 22.6 million tons, or 98% of estimated sales volumes based on the midpoint of guidance. For 2016, CONSOL Energy contracted for 1.3 million additional tons during the second quarter, bringing the total firm and priced contracted position to 14.2 million tons, or 54% (and sold position to 15.7 million tons, or 60%) of expected sales volumes based on the midpoint of guidance. For 2017 and 2018 combined, CONSOL Energy’s sold position is averaged at 40% of expected sales volumes. The company continues to work with customers to lock in multi-year deals and expects to significantly increase committed volumes in 2017 and 2018 throughout the year.

In the second quarter of 2015, CONSOL Energy sold 1.1 million tons of its Buchanan low-vol coal. Buchanan continued to expand its customer base with a new sales opportunity in Europe. The new opportunity in Europe, combined with existing business from traditional customers, enabled the Buchanan Mine to achieve the high end of its second quarter sales forecast. During the quarter, CONSOL Energy contracted for 0.5 million additional tons for 2015 and expects additional contracting opportunities throughout the year. CONSOL Energy expects to ship approximately 80% of Buchanan Mine’s production to customers in the U.S. and Atlantic Basin in 2015.

Also in the second quarter, CONSOL Energy sold 0.5 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 third quarter 2015 gas production to be approximately 75 – 79 Bcfe, while annual 2015 production guidance remains between 300 – 310 Bcfe, or 30% growth compared to 2014 total production. CONSOL Energy continues to expect 2016 annual gas production to grow by 20%.

Total hedged natural gas production in the 2015 third quarter is 39.3 Bcf, at an average price of $3.87 per Mcf. The annual gas hedge position for two years is shown in the table below:



	2015	2016
Total Yearly Production (Bcfe) / % growth	300-310	+20%
Volumes Hedged (Bcf), as of 7/09/15	140.8*	110.9
Average Hedge Price ($/Mcf)	$3.94	$3.97

* Includes actual settlements of 62.1 Bcf.

The hedged gas volumes shown in the previous table include the following NYMEX hedges that have basis hedged as well.



NYMEX PLUS BASIS HEDGES	2015		2016
Columbia (TCO)
Volume (Bcf)	49.6		76.2
Average Hedge Price ($/Mcf)	$	3.84	$	3.69
Texas Eastern (TETCO)
Volume (Bcf)	3.5		-
Average Hedge Price ($/Mcf)	$	3.93	-

COAL DIVISION GUIDANCE

For full year 2015, Pennsylvania Operations sales guidance is lower, compared to previous quarter's guidance, due to a reduced operating schedule. Starting in June and prior to the IPO roadshow, CONSOL Energy decided to move to a four-day operating schedule, compared to five days previously, in order to better align production to contracted sales and preserve margins. CONSOL Energy expects to maintain the four-day schedule through the remainder of 2015, while continuing to focus on further reducing costs.

The following table describes the forecasted contracted position (in millions of tons) for the years ending December 31, 2015 and 2016 as of July 28, 2015:



	Q3 2015		2015		2016
Est. Total Coal Sales	6.6 - 7.1		28.4 - 29.9		30.6 - 33.4
Committed	6.1		27.5		15.6
Estimated Price (committed tons)	$	60.56	$	59.88	$	59.97
Est. PA Operations Sales	5.4 - 5.6		22.5 - 23.5		25.0 - 27.0
Committed	5.4		22.6		14.2
Est. VA Operations Sales	0.8 - 1.0		3.9 - 4.2		3.7 - 4.2
Committed	0.2		2.9		0.7
Est. Other Sales	0.4 - 0.5		2.0 - 2.2		1.9 - 2.2
Committed	0.5		2.0		0.7

NOTE: Committed tons include tons that are both sold 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. Not included in the table are the tons from Western Allegheny Energy (WAE). We forecast WAE production of 0.2 million tons for Q3 2015, and 0.5 million tons and 0.4 million tons for all of 2015, and 2016, respectively. For purposes of this table, the forecasted 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 forecasted prices set forth in the table above were based in part on certain assumptions made by management. With respect to clause (i) quality characteristics, for 2016 we assumed that the coal we will deliver will be within the contract range, and no premiums or penalties relating to the quality of coal delivered are forecasted. For the current year, 2015, we based our assumption on our average monthly forecasted 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, for 2016 we assumed that the coal we deliver will be within the contract range, and no premiums or penalties relating to the calorific value of coal delivered are forecasted. For the current year, 2015, we based our assumption on our average monthly forecasted 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 forecasted information regarding contract specific factors that impact pricing. The key assumptions used for the forecasted 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 forecasted prices, including with respect to forecasted 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.

Over the past three quarters CONSOL Energy has aggressively developed a durable and transparent structure that will allow the company to more efficiently allocate cash flows and liquidity across all of the business segments. CONE Midstream Partners contains the midstream gathering assets across the Marcellus Shale joint venture and is a major contributor responsible for supporting future growth. CNX Coal Resources LP serves as the company’s thermal coal entity where additional ownership interests in CONSOL Energy's Pennsylvania thermal coal mines will get dropped down over time. If CONSOL Energy decides to not pursue a stand-alone metallurgical coal entity, CNX Coal Resources has a right of first offer to acquire these assets for additional growth. In addition to the structural changes, CONSOL Energy has modernized its debt covenants, which allows for a greater level of flexibility. CONSOL Energy continues to effectively manage the growing E&P Division with the sustained goal of evolving into a pure play Appalachian Shale entity. Today the company sits with the necessary components and structure to drive net asset value (NAV) moving forward.

Over the past 18 months the company has aggressively implemented a number of key concepts to unlock NAV per share to include zero-based budgeting and lean manufacturing. Cumulatively, these concepts have improved safety performance, reduced E&P capital intensity, administrative, overhead, “other” spend, and balance sheet liabilities. The continued application of these concepts will have an even greater impact on the company's performance in the coming quarters. The following summarizes many of these areas, the progress already made, and future expectations:

E&P Division Production Growth, Capital Intensity, and Unit Costs:

CONSOL Energy believes a number of factors within the E&P division should create the confluence of production growth and reduced capital intensity. Well profiles continue to improve across both the Marcellus and Utica shales; lean manufacturing techniques continue to compress cycle times across development activities including permitting, construction, water infrastructure, drilling, completions, and midstream; de-bottlenecking efforts in producing areas should provide low-cost incremental production growth that allows for the deferral of capital for new wells; economies of scale from pooled resources allow for the tightening of capital outlays. Also, in the near future, stacked pay opportunities across the Upper Devonian, Marcellus, and Utica shales should decrease capital intensity further.

The culmination of these factors will positively impact E&P production and lower capital intensity through 2016, while allowing CONSOL Energy to achieve its production growth targets. As a result, CONSOL Energy has reduced the second half of 2015 E&P capital budget to approximately $250 million. When combined with the $539 million of E&P capital expenditures in the first half of 2015, which includes CONE gathering midstream capital, total 2015 E&P capital investment is now expected to be approximately $800 million, down from $1.0 billion at the start of the year.

Also, the 2016 E&P capital budget is expected to be approximately $400 - $500 million. CONSOL Energy expects cumulative capital investment for the E&P division for the second half of 2015 and all of 2016 to include developing an inventory of future permitted locations and pads for 2017 and beyond.

Also, the production growth and capital investment targets through 2016 do not assume opportunities resulting from the dry Utica and stacked pays. CONSOL Energy intends to provide any improvements to future production or capital intensity as results from the dry Utica are assessed. Lastly, CONSOL Energy will formalize 2017 production growth targets around mid-2016, once stacked pay opportunities are further evaluated.

The E&P Division's total unit costs declined steadily over the past year. For example, during the second quarter, the E&P Division drove down total unit costs to $2.90 per Mcfe, compared to $3.44 per Mcfe during the year-earlier quarter. In-line with previous guidance, and ahead of the forecasted timeline, CONSOL Energy’s E&P Division has achieved reducing total operating costs between 10% -15%, when compared to 2014. CONSOL Energy expects to further reduce total unit costs through 2016. The drivers of this trend include many of the same factors in reducing capital intensity, along with deflation of service costs, consumables and optimization of support personnel through zero-based budgeting. In addition, CONSOL Energy expects that DD&A rates from the shallow oil and gas assets will decline from $2.25 per Mcfe in 2014 to approximately $0.35 per Mcfe in the second half of 2015 and 2016 due to the aforementioned unusual impairment charge during the quarter. CONSOL Energy expects that the culmination of these factors will result in the E&P Division total unit costs to further decline between 10% - 15% through 2016, when compared to the second quarter 2015.

Coal Division Production, Unit Costs, and Capital:

The Coal Division continues to achieve production targets, deliver unit cost improvements, and build future sales volumes. Moving forward, CNX Coal Resources will discuss more of the details associated with Pennsylvania Operations.

In the Pennsylvania Operations, CONSOL Energy expects total unit costs to improve in the second half of 2015 due to no additional planned longwall moves, better geological conditions, and a continued focus on cost reduction efforts. For full year 2015, CONSOL Energy expects total unit costs, including DD&A, to be between $40 - $43 per ton.

In the Virginia Operations, as discussed last quarter, better utilization from previously completed efficiency projects and reduced travel time to the face of the longwall have resulted in significantly improved operating cost performance at the Buchanan Mine. However, as expected, these improvements were offset somewhat due to the planned longwall move and a scheduled outage to perform a maintenance upgrade during the quarter. As stated last quarter, CONSOL Energy continues to expect Virginia Operations 2015 total unit costs, including DD&A, to be $50 - $55 per ton due primarily to lower forecasted quarterly tons for the remainder of the year, compared to the first half, as well as the company planning to bring back a development section early in the third quarter.

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

CONSOL Energy continues to expect maintenance of production capital expenditures between $4.00 - $5.00 per ton moving forward.

Administrative and Overhead Costs:

CONSOL Energy continues to apply zero-based budgeting across the operating segments and corporate functions. This focuses attention to critical path items, streamlines the organizational structure, and eliminates bureaucracy. In 2015 year-to-date (YTD), CONSOL Energy has reduced corporate headcount by approximately 30%, compared to year-end 2014 levels. Company-wide executive positions have been reduced by 27%, over the same period, and are expected to hit 40% by year-end 2015. Due to additional headcount right-sizing and zero-based budgeting efforts, CONSOL Energy now expects approximately $100 million in administrative and overhead costs reductions in 2015, when compared to 2014. When compared to last quarter estimates, this is an improvement of approximately $35 million and $48 million in 2015 and 2016, respectively.

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

Net (Loss) Income

CONSOL Energy reported a net loss of $ 603 million, or a loss of $ 2.64 per diluted share, for the three months ended June 30, 2015 , compared to a net loss of $ 25 million, or a loss of $ 0.11 per diluted share, for the three months ended June 30, 2014 .

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

The total Exploration and Production (E&P) division contributed a loss of $ 891 million before income tax for the three months ended June 30, 2015 compared to $ 23 million of earnings before income tax for the three months ended June 30, 2014 . Total E&P production was 75.5 Bcfe for the three months ended June 30, 2015 compared to 51.9 Bcfe for the three months ended June 30, 2014 . Included in the net loss was a 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 Three Months Ended June 30,
in thousands (unless noted)	2015		2014			Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	7,235		1,919			5,316			277.0	%
Sales Volume (Mbbls)	1,206		320			886			276.9	%
Gross Price ($/Bbl)	$	12.48	$	55.56		$	(43.08	)	(77.5	)%
Gross Revenue	$	15,021	$	17,772		$	(2,751	)	(15.5	)%

Oil:
Sales Volume (MMcfe)	162		181			(19		)	(10.5	)%
Sales Volume (Mbbls)	27		30			(3		)	(10.0	)%
Gross Price ($/Bbl)	$	46.14	$	95.10		$	(48.96	)	(51.5	)%
Gross Revenue	$	1,243	$	2,867		$	(1,624	)	(56.6	)%

Condensate:
Sales Volume (MMcfe)	1,668		479			1,189			248.2	%
Sales Volume (Mbbls)	278		80			198			247.5	%
Gross Price ($/Bbl)	$	31.26	$	94.92		$	(63.66	)	(67.1	)%
Gross Revenue	$	8,690	$	7,585		$	1,105		14.6	%

GAS
Sales Volume (MMcf)	66,426		49,295			17,131			34.8	%
Sales Price ($/Mcf)	$	2.03	$	4.23		$	(2.20	)	(52.0	)%
Hedging Impact ($/Mcf)	$	0.64	$	(0.13	)	$	0.77		592.3	%
Gross Revenue including Hedging Impact	$	177,305	$	202,075		$	(24,770	)	(12.3	)%

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



	For the Three Months Ended June 30,
	2015			2014		Variance			Percent Change
Average Sales Price (per Mcfe)	$	2.68		$	4.44	$	(1.76	)	(39.6	)%
Average Costs (per Mcfe)	2.90			3.44		(0.54		)	(15.7	)%
Margin	$	(0.22	)	$	1.00	$	(1.22	)	(122.0	)%

Total E&P division Natural Gas, NGLs, and Oil outside sales revenues were $ 202 million for the three months ended June 30, 2015 compared to $ 230 million for the three months ended June 30, 2014 . The decrease was primarily due to the 39.6% decrease in average sales price per Mcfe, offset in part, by the 45.5% 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 32.2 Bcf of our produced gas sales volumes for the three months ended June 30, 2015 at an average gain of $1.31 per Mcf. These economic hedges represented approximately 41.3 Bcf of our produced gas sales volumes for the three months ended June 30, 2014 at an average loss of $0.16 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 34.8% increase in gas sales volumes in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 51.6% of natural gas and liquid sales volumes for the three months ended June 30, 2015 compared to 45.8% in the three months ended June 30, 2014 .


•	Depreciation, depletion and amortization decreased on a unit basis due to 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 the portion of production from higher investment cost segments continued to grow.


•	Lifting costs also decreased on unit basis in the period-to-period comparison due to the increase in volumes sold. The decrease in unit costs was partially offset by an increase in salt water disposal, repairs and maintenance and environmental and safety costs.

The total coal division contributed $55 million of earnings before income tax for the three months ended June 30, 2015 compared to $122 million of earnings before income tax for the three months ended June 30, 2014 . The total coal division sold 7.3 million tons of coal produced from CONSOL Energy mines for the three months ended June 30, 2015 compared to 8.5 million tons for the three months ended June 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 June 30,
	2015		2014		Variance			Percent Change
Average Sales Price per ton sold	$	56.78	$	62.43	$	(5.65	)	(9.1	)%
Average Cost of Goods Sold per ton	45.69		47.63		(1.94		)	(4.1	)%
Margin	$	11.09	$	14.80	$	(3.71	)	(25.1	)%

The lower average sales price per ton sold reflects a 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 1.9 million tons on the export market for the three months ended June 30, 2015 compared to 1.5 million tons for the three months ended June 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) offset, in part, by various long wall moves throughout the three months ended June, 30, 2015.

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. G&A costs are excluded from the E&P and Coal unit costs above. G&A costs were $21 million for the three months ended June 30, 2015 compared to $26 million for the three months ended June 30, 2014 . G&A costs decreased due to the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Consulting and Professional Services	$	5	$	7	$	(2	)	(28.6	)%
Employee Wages and Related Expenses	10		11		(1		)	(9.1	)%
Contributions	1		1		—			—	%
Advertising and Promotion	2		2		—			—	%
Miscellaneous	3		5		(2		)	(40.0	)%
Total Company General and Administrative Expense	$	21	$	26	$	(5	)	(19.2	)%


•	Consulting and professional services decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Employee Wages and Related Expenses decreased $1 million due to reductions in headcount in the three months ended June 30, 2015 .


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


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


•	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 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 $18 million for the three months ended June 30, 2015 , compared to expense of $52 million for the three months ended June 30, 2014 . The decrease of $70 million to total Company expense was primarily due to modifications made to the OPEB and Pension plans in September 2014 and May 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 - 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 of 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 June 30, 2015 compared to the three months ended June 30, 2014 :

The E&P division had a loss before income tax of $ 891 million for the three months ended June 30, 2015 compared to earnings before income tax of $ 23 million in the three months ended June 30, 2014 . Variances by individual E&P segment are discussed below.



	For the Three Months Ended														Difference to Three Months Ended
	June 30, 2015														June 30, 2014
(in millions)	Marcellus			Utica			CBM		Other Gas			Total E&P			Marcellus			Utica			CBM			Other Gas			Total E&P
Sales:
Produced	$	98		$	18		$	66	$	20		$	202		$	(7	)	$	4		$	(15	)	$	(10	)	$	(28	)
Related Party	—			—			—		—			—			—			—			(1		)	—			(1		)
Total Outside Sales	98			18			66		20			202			(7		)	4			(16		)	(10		)	(29		)
Unrealized Loss on Commodity Derivative Instruments	—			—			—		(25		)	(25		)	—			—			—			(25		)	(25		)
Production Royalty Interest	—			—			—		5			5			—			—			—			(13		)	(13		)
Purchased Gas	—			—			—		2			2			—			—			—			1			1
Miscellaneous Other Income	—			—			—		15			15			—			—			—			6			6
Gain on Sale of Assets	—			—			—		1			1			—			—			—			(2		)	(2		)
Total Revenue and Other Income	98			18			66		18			200			(7		)	4			(16		)	(43		)	(62		)
Lifting	8			3			8		6			25			3			(1		)	(2		)	(1		)	(1		)
Ad Valorem, Severance, and Other Taxes	4			—			2		1			7			—			—			(1		)	(2		)	(3		)
Transportation, Gathering and Compression	48			8			24		7			87			24			7			(2		)	—			29
Gas Direct Administrative, Selling & Other	7			2			2		2			13			(2		)	1			(1		)	1			(1		)
Depreciation, Depletion and Amortization	38			12			20		18			88			10			9			(2		)	—			17
General & Administration	—			—			—		14			14			—			—			—			(2		)	(2		)
Production Royalty Interest	—			—			—		3			3			—			—			—			(13		)	(13		)
Purchased Gas	—			—			—		1			1			—			—			—			—			—
Exploration and Other Costs	—			—			—		2			2			—			—			—			(2		)	(2		)
Other Corporate Expenses	—			—			—		850			850			—			—			—			829			829
Total Exploration and Production Costs	105			25			56		904			1,090			35			16			(8		)	810			853
Interest Expense	—			—			—		1			1			—			—			—			(1		)	(1		)
Total E&P Division Costs	105			25			56		905			1,091			35			16			(8		)	809			852
Earnings (Loss) Before Income Tax	$	(7	)	$	(7	)	$	10	$	(887	)	$	(891	)	$	(42	)	$	(12	)	$	(8	)	$	(852	)	$	(914	)

MARCELLUS GAS SEGMENT

The Marcellus segment had a loss before income tax of $ 7 million for the three months ended June 30, 2015 compared to earnings before income tax of $ 35 million for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
	2015			2014			Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	33.6			22.0			11.6			52.7	%
NGLs Sales Volumes (Bcfe)*	4.5			1.6			2.9			181.3	%
Condensate Sales Volumes (Bcfe)*	0.9			0.2			0.7			350.0	%
Total Marcellus Sales Volumes (Bcfe)*	39.0			23.8			15.2			63.9	%

Average Sales Price - Gas (Mcf)	$	1.89		$	4.09		$	(2.20	)	(53.8	)%
Derivative Impact - Gas (Mcf)	$	0.53		$	(0.10	)	$	0.63		630.0	%
Average Sales Price - NGLs (Mcfe)*	$	2.65		$	9.11		$	(6.46	)	(70.9	)%
Average Sales Price - Condensate (Mcfe)*	$	5.37		$	13.70		$	(8.33	)	(60.8	)%

Total Average Marcellus sales (per Mcfe)	$	2.50		$	4.40		$	(1.90	)	(43.2	)%
Average Marcellus lifting costs (per Mcfe)	0.20			0.20			—			—	%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	0.10			0.19			(0.09		)	(47.4	)%
Average Marcellus transportation, gathering, and compression costs (per Mcfe)	1.23			0.99			0.24			24.2	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	0.19			0.37			(0.18		)	(48.6	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	0.96			1.19			(0.23		)	(19.3	)%
Total Average Marcellus costs (per Mcfe)	$	2.68		$	2.94		$	(0.26	)	(8.8	)%
Average Margin for Marcellus (per Mcfe)	$	(0.18	)	$	1.46		$	(1.64	)	(112.3	)%

* 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 $ 98 million for the three months ended June 30, 2015 compared to $ 105 million for the three months ended June 30, 2014 . The $ 7 million decrease is primarily due to a 43.2% decrease in total average sales price in the period-to-period comparison, partially offset by a 63.9% increase in total volumes sold. The decrease in Marcellus total average sales price was primarily the result of the $ 2.20 per Mcf decrease in gas market prices, along with a $0.24 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 $ 0.63 per Mcf increase resulting from various transactions from our hedging program. These economic hedges represented approximately 14.1 Bcf of our produced Marcellus gas sales volumes for the three months ended June 30, 2015 at an average gain of $1.26 per Mcf. For the three months ended June 30, 2014 , these economic hedges represented approximately 17.3 Bcf at an average loss of $0.12 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 $ 105 million for the three months ended June 30, 2015 compared to $ 70 million for the three months ended June 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 June 30, 2015 compared to $ 5 million for the three months ended June 30, 2014 . The increase in total dollars primarily relates to the 63.9% increase in total sales volumes. Unit costs remained consistent in the period-to-period comparison.

• Marcellus ad valorem, severance and other taxes were $ 4 million for the three months ended June 30, 2015 and 2014. The decrease in unit costs was due to the increase in gas sales volumes, offset, in part, by the decrease in gas market prices.

• Marcellus transportation, gathering, and compression costs were $ 48 million for the three months ended June 30, 2015 compared to $ 24 million for the three months ended June 30, 2014 . The increase in total dollars primarily relates to an increase in CONE gathering fees due to the 52.7% 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 181.3% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increase in unit costs due to the increase in total dollars was offset, in part, by the increase in gas sales volumes.

• Marcellus direct administrative, selling and other costs were $ 7 million for the three months ended June 30, 2015 compared to $ 9 million for the three months ended June 30, 2014 . Direct administrative, selling and other 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. Unit costs were also positively impacted by the increase in gas sales volumes.

• Depreciation, depletion and amortization costs were $ 38 million for the three months ended June 30, 2015 compared to $ 28 million for the three months ended June 30, 2014 . These amounts included depreciation on a per unit basis of $0.95 per Mcf and $1.16 per Mcf, respectively. The remaining amount of 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 $ 7 million for the three months ended June 30, 2015 compared to earnings before income tax of $ 5 million for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
	2015			2014			Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	7.1			1.1			6.0			545.5	%
NGLs Sales Volumes (Bcfe)*	2.7			0.3			2.4			800.0	%
Condensate Sales Volumes (Bcfe)*	0.8			0.3			0.5			166.7	%
Total Utica Sales Volumes (Bcfe)*	10.6			1.7			8.9			523.5	%

Average Sales Price - Gas (Mcf)	$	1.45		$	4.46		$	(3.01	)	(67.5	)%
Derivative Impact - Gas (Mcf)	$	—		$	(0.13	)	$	0.13		100.0	%
Average Sales Price - NGLs (Mcfe)*	$	1.10		$	9.91		$	(8.81	)	(88.9	)%
Average Sales Price - Condensate (Mcfe)*	$	5.05		$	17.01		$	(11.96	)	(70.3	)%

Total Average Utica sales price (per Mcfe)	$	1.66		$	7.71		$	(6.05	)	(78.5	)%
Average Utica lifting costs (per Mcfe)	0.27			2.10			(1.83		)	(87.1	)%
Average Utica ad valorem, severance, and other taxes (per Mcfe)	—			0.17			(0.17		)	(100.0	)%
Average Utica transportation, gathering, and compression costs (per Mcfe)	0.79			0.54			0.25			46.3	%
Average Utica direct administrative, selling & other costs (per Mcfe)	0.17			0.46			(0.29		)	(63.0	)%
Average Utica depreciation, depletion and amortization costs (per Mcfe)	1.08			1.74			(0.66		)	(37.9	)%
Total Average Utica costs (per Mcfe)	$	2.31		$	5.01		$	(2.70	)	(53.9	)%
Average Margin for Utica (per Mcfe)	$	(0.65	)	$	2.70		$	(3.35	)	(124.1	)%

*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.

Utica outside sales revenues were $ 18 million for the three months ended June 30, 2015 compared to $ 14 million for the three months ended June 30, 2014 . The $ 4 million increase was primarily due to the 523.5% increase in total volumes sold partially offset by the 78.5% decrease in the total average sales price. The 8.9 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 $3.01 per Mcf decrease in average market prices, as well as a $3.12 decrease in the uplift from natural gas liquids and condensate. None of our produced Utica sales volumes were hedged for the three months ended June 30, 2015 , which improved our average sales price $0.13 per Mcf when compared to the three months ended June 30, 2014 . Economic hedges represented approximately 1.0 Bcf of produced Utica gas sales volumes at an average loss of $0.13 per Mcf for the three months ended June 30, 2014 .

Total costs for the Utica segment were $ 25 million for the three months ended June 30, 2015 compared to $ 9 million for the three months ended June 30, 2014 . The increase in total dollars and decrease in unit costs were all directly related to the 523.5% 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 $ 10 million to the total Company earnings before income tax for the three months ended June 30, 2015 compared to $ 18 million of earnings before income tax for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
	2015		2014			Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	18.8		19.7			(0.9		)	(4.6	)%

Average Sales Price - Gas (Mcf)	$	2.50	$	4.31		$	(1.81	)	(42.0	)%
Derivative Impact - Gas (Mcf)	$	0.99	$	(0.19	)	$	1.18		621.1	%

Total Average CBM sales price (per Mcf)	$	3.49	$	4.12		$	(0.63	)	(15.3	)%
Average CBM lifting costs (per Mcf)	0.42		0.49			(0.07		)	(14.3	)%
Average CBM ad valorem, severance, and other taxes (per Mcf)	0.10		0.14			(0.04		)	(28.6	)%
Average CBM transportation, gathering, and compression costs (per Mcfe)	1.25		1.33			(0.08		)	(6.0	)%
Average CBM direct administrative, selling & other costs (per Mcf)	0.11		0.13			(0.02		)	(15.4	)%
Average CBM depreciation, depletion and amortization costs (per Mcf)	1.09		1.12			(0.03		)	(2.7	)%
Total Average CBM costs (per Mcf)	$	2.97	$	3.21		$	(0.24	)	(7.5	)%
Average Margin for CBM (per Mcf)	$	0.52	$	0.91		$	(0.39	)	(42.9	)%

CBM outside sales revenues were $ 66 million in the three months ended June 30, 2015 compared to $ 82 million for the three months ended June 30, 2014 . The $ 16 million decrease was primarily due to a 15.3% decrease in the total average sales price per Mcf as well as a 4.6% 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 $0.63 per Mcf due to a $1.81 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $1.18 per Mcf increase due to various transactions from our hedging program. These economic hedges represented approximately 13.7 Bcf of our produced CBM gas sales volumes for the three months ended June 30, 2015 at an average gain of $1.37 per Mcf. For the three months ended June 30, 2014 , these economic hedges represented approximately 18.5 Bcf at an average loss of $0.20 per Mcf.

Total costs for the CBM segment were $ 56 million for the three months ended June 30, 2015 compared to $ 64 million for the three months ended June 30, 2014 . The decrease in total dollars and unit costs for the CBM segment were due to the following items:

• CBM lifting costs were $ 8 million for the three months ended June 30, 2015 compared to $ 10 million for the three months ended June 30, 2014 . The decrease in total dollars was primarily related to a decrease in contractual services related to well tending and a decrease in salt water disposal 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 June 30, 2015 compared to $ 3 million for the three months ended June 30, 2014 . The decrease of $ 1 million was due to a decrease in severance tax expense resulting from the decrease in average sales price, without the impact of hedging, as described above. 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 $ 24 million for the three months ended June 30, 2015 compared to $ 26 million for the three months ended June 30, 2014 . The decrease of $ 2 million is due to a decrease in non-critical pipeline repairs resulting from cost cutting measures. 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, selling and other costs were $ 2 million for the three months ended June 30, 2015 compared to $ 3 million for the three months ended June 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. 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 June 30, 2015 compared to $ 22 million for the three months ended June 30, 2014 . These amounts included depreciation on a per unit basis of $0.73 per Mcf and $0.75 per Mcf, respectively. The remaining amount of 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 $ 887 million for the three months ended June 30, 2015 compared to a loss before income tax of $ 35 million for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
	2015			2014			Variance			Percent Change
Other Gas Sales Volumes (Bcf)	6.9			6.5			0.4			6.2	%
Oil Sales Volumes (Bcfe)*	0.2			0.1			0.1			100.0	%
Total Other Sales Volumes (Bcfe)*	7.1			6.6			0.5			7.6	%

Average Sales Price - Gas (Mcf)	$	2.06		$	4.43		$	(2.37	)	(53.5	)%
Derivative Impact - Gas (Mcf)	$	0.82		$	(0.08	)	$	0.90		1,125.0	%
Average Sales Price - Oil (Mcfe)*	$	7.89		$	15.86		$	(7.97	)	(50.3	)%

Total Average Other sales price (per Mcfe)	$	2.98		$	4.66		$	(1.68	)	(36.1	)%
Average Other lifting costs (per Mcfe)	0.95			1.24			(0.29		)	(23.4	)%
Average Other ad valorem, severance, and other taxes (per Mcfe)	0.13			0.40			(0.27		)	(67.5	)%
Average Other transportation, gathering, and compression costs (per Mcfe)	1.01			1.07			(0.06		)	(5.6	)%
Average Other direct administrative, selling & other costs (per Mcfe)	0.28			0.20			0.08			40.0	%
Average Other depreciation, depletion and amortization costs (per Mcfe)	2.38			2.59			(0.21		)	(8.1	)%
Total Average Other costs (per Mcfe)	$	4.75		$	5.50		$	(0.75	)	(13.6	)%
Average Margin for Other (per Mcfe)	$	(1.77	)	$	(0.84	)	$	(0.93	)	(110.7	)%

*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 includes purchased gas activity, production royalty interest activity, 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 three months ended June 30, 2015 compared to $30 million for the three months ended June 30, 2014 . The decrease in outside sales revenue primarily relates to the $1.68 decrease in total average sales price. Total costs related to these other sales were $34 million for the three months ended June 30, 2015 compared to $36 million for the three months ended June 30, 2014 .

Unrealized loss on commodity derivative instruments represents changes in fair value of all existing gas commodity hedges on a mark-to-market basis. Unrealized loss on commodity derivative instruments decreased $ 25 million due to the December 31, 2014 de-designation of all our derivative positions as hedging instruments. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.

months ended June 30, 2015 compared to $18 million for the three months ended June 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 June 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	5.5		4.9		0.6			12.2	%
Average Sales Price Per thousand cubic feet	$	0.97	$	3.76	$	(2.79	)	(74.2	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $2 million for the three months ended June 30, 2015 compared to $ 1 million for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
	2015		2014		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.7		0.3		0.4			133.3	%
Average Sales Price Per thousand cubic feet	$	2.16	$	4.40	$	(2.24	)	(50.9	)%

Miscellaneous other income was $15 million for the three months ended June 30, 2015 compared to $9 million for the three months ended June 30, 2014 . The $6 million increase was primarily due to the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance		Percent Change
Equity in Earnings of Affiliates	10		7		$	3	42.9	%
Gathering Revenue	2		2		—		—	%
Other	3		—		3		100.0	%
Total Miscellaneous Other Income	$	15	$	9	$	6	66.7	%


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


•	The remaining $ 3 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 June 30, 2015 compared to $3 million for the three months ended June 30, 2014 . The $2 million decrease was due to various transactions that occurred throughout both periods, none of which were individually significant.

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 $14 million for the three months ended June 30, 2015 compared to $16 million for the three months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report 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 $3 million for the three months ended June 30, 2015 compared to $16 million for the three months ended June 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 June 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	5.5		4.9		0.6			12.2	%
Average Cost Per thousand cubic feet sold	$	0.46	$	3.20	$	(2.74	)	(85.6	)%

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 $1 million for the three months ended June 30, 2015 and 2014.



	For the Three Months Ended June 30,
	2015		2014		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.3		0.4			133.3	%
Average Cost Per thousand cubic feet sold	$	1.51	$	3.32	$	(1.81	)	(54.5	)%

Exploration and other costs were $2 million for the three months ended June 30, 2015 compared to $4 million for the three months ended June 30, 2014 . The $2 million decrease is due to the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Land Rentals	$	1	$	1	$	—		—	%
Lease Expiration Costs	1		1		—			—	%
Other	—		2		(2		)	(100.0	)%
Total Exploration and Other Costs	$	2	$	4	$	(2	)	(50.0	)%


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


•	Lease expiration costs remained consistent in the period-to-period comparison.


•	The remaining $ 2 million decrease related to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $850 million for the three months ended June 30, 2015 compared to $ 21 million for the three months ended June 30, 2014 . The $ 829 million increase in the period-to-period comparison was made up of the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Impairment of Exploration and Production Properties	$	829	$	—	$	829		100.0	%
Idle Rig Fees	3		—		3			100.0	%
Stock-Based Compensation	4		4		—			—	%
Short-Term Incentive Compensation	4		5		(1		)	(20.0	)%
Bank Fees	—		2		(2		)	(100.0	)%
Unutilized Firm Transportation and Processing Fees	7		10		(3		)	(30.0	)%
Other	3		—		3			100.0	%
Total Other Corporate Expenses	$	850	$	21	$	829		3,947.6	%


•	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 our natural gas rigs.


•	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.


•	Bank fees decreased $ 2 million due to the termination of the CNX Gas Senior Secured Credit Agreement on June 18, 2014.


•	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 $ 3 million in the period-to-period comparison due to an increase in the utilization of the capacity.


•	Other corporate related expenses increased $ 3 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 June 30, 2015 compared to $ 2 million for the three months ended June 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, and a capital lease.

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

The coal division contributed $55 million of earnings before income tax for the three months ended June 30, 2015 compared to $122 million for the three months ended June 30, 2014 . Variances by the individual coal segments are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	June 30, 2015											June 30, 2014
(in millions)	Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal		Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal
Sales:
Produced Coal	$	319		$	63		$	32		$	414	$	(116	)	$	(4	)	$	—		$	(120	)
Purchased Coal	—			—			—			—		—			—			(3		)	(3		)
Total Coal Sales	319			63			32			414		(116		)	(4		)	(3		)	(123		)
Other Outside Sales	—			—			6			6		—			—			(4		)	(4		)
Freight Revenue	3			—			1			4		(4		)	—			(2		)	(6		)
Miscellaneous Other Income	—			—			21			21		(34		)	—			(4		)	(38		)
Gain on Sale of Assets	—			—			3			3		—			—			5			5
Total Revenue and Other Income	322			63			63			448		(154		)	(4		)	(8		)	(166		)
Cost of Coal Sold:
Operating Costs	186			40			24			250		(61		)	(3		)	(1		)	(65		)
Direct Administrative and Selling	6			1			1			8		(3		)	—			—			(3		)
Total Royalty/Production Taxes	15			3			3			21		(5		)	(1		)	—			(6		)
Depreciation, Depletion and Amortization	44			9			1			54		2			—			(1		)	1
Total Cost of Coal Sold:	251			53			29			333		(67		)	(4		)	(2		)	(73		)
Other Costs and Expenses:
Other Costs	(11		)	(4		)	36			21		(13		)	(7		)	1			(19		)
Direct Administrative and Selling	—			—			1			1		—			—			—			—
Total Royalty/Production taxes	—			—			1			1		—			—			1			1
Depreciation, Depletion and Amortization	3			3			7			13		1			—			(1		)	—
Total Other Costs and Expenses:	(8		)	(1		)	45			36		(12		)	(7		)	1			(18		)
General and Administrative Expense	5			1			1			7		(1		)	(1		)	(1		)	(3		)
Other Corporate Expense	9			3			1			13		—			1			—			1
Freight Expense	3			—			1			4		(4		)	—			(2		)	(6		)
Total Costs	260			56			77			393		(84		)	(11		)	(4		)	(99		)
Earnings (Loss) Before Income Taxes	$	62		$	7		$	(14	)	$	55	$	(70	)	$	7		$	(4	)	$	(67	)

PENNSYLVANIA (PA) OPERATIONS COAL SEGMENT

The PA Operations coal segment's principal activities are 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 June 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 $62 million to total Company earnings before income taxes for the three months ended June 30, 2015 compared to $132 million of earnings before income taxes for the three months ended June 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 June 30,
	2015		2014		Variance			Percent Change
Company Produced PA Operations Tons Sold (in millions)	5.7		7.1		(1.4		)	(19.8	)%
Average Sales Price Per PA Operations Ton Sold	$	56.21	$	61.47	$	(5.26	)	(8.6	)%

Total Operating Costs Per Ton Sold	$	33.25	$	34.57	$	(1.32	)	(3.8	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.11		1.29		(0.18		)	(14.0	)%
Total Royalty/Production Taxes Per Ton Sold	2.49		2.99		(0.50		)	(16.7	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	7.45		6.17		1.28			20.7	%
Total Costs Per PA Operations Ton Sold	$	44.30	$	45.02	$	(0.72	)	(1.6	)%
Average Margin Per PA Operations Ton Sold	$	11.91	$	16.45	$	(4.54	)	(27.6	)%

Coal Sales

PA Operations produced coal outside sales revenues were $ 319 million for the three months ended June 30, 2015 compared to $435 million for the three months ended June 30, 2014 . The $116 million decrease was attributable to a 1.4 million decrease in tons sold and a $5.26 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 overall 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 (i.e. rail) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $3 million for the three months ended June 30, 2015 compared to $7 million for the three months ended June 30, 2014 . The $4 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

There was no Miscellaneous other income for the three months ended June 30, 2015 compared to $34 million for the three months ended June 30, 2014 . Approximately $30 million related to a coal customer contract buyout. The discontinued contract was a long-term contract that created pricing risks for both parties. An amicable settlement was reached. The remaining $4 million decrease was a result of various transactions that occurred during the three month period ended June 30, 2014 , 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 $251 million for the three months ended June 30, 2015 , or $67 million lower than the $318 million for the three months ended June 30, 2014 . Total costs per PA Operations ton sold were $44.30 per ton for the three months ended June 30, 2015 compared to $45.02 per ton for the three months ended June 30, 2014 . The decrease in the cost of coal sold is a result of a decrease of 1.4 million tons sold, along with 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 (Loss) Income" of this quarterly report 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 $12 million in the three months ended June 30, 2015 compared to the three months ended June 30, 2014 . This decrease was primarily attributable to $19 million of income due to modifications made to the Pension and OPEB plans in September 2014 for active employees and in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income" of this quarterly report for a detailed cost explanation. This was partially offset by $7 million of accelerated amortization of financing charges related to a backstop loan.

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. The amount of general and administrative costs allocated to PA Operations was $5 million for the three months ended June 30, 2015 compared to $6 million for the three months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report 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. Other corporate expenses remained consistent in the period-to-period comparison.

Freight Expense

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. 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 three months ended June 30, 2015 , freight expense was $3 million compared to $7 million for the three months ended June 30, 2014 . The $4 million decrease was due to decreased shipments under contracts where CONSOL Energy contractually provides transportation services.

VIRGINIA (VA) OPERATIONS COAL SEGMENT

The VA Operations coal segment's principal activities are 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 June 30, 2015 and 2014 , the segment included Buchanan Mine and the corresponding preparation plant facilities.

The VA Operations coal segment contributed $7 million to total Company earnings before income tax for the three months ended June 30, 2015 , and had no earnings before income tax for the three months ended June 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 June 30,
	2015		2014		Variance			Percent Change
Company Produced VA Operations Tons Sold (in millions)	1.1		0.9		0.2			22.2	%
Average Sales Price Per VA Operations Ton Sold	$	57.76	$	70.99	$	(13.23	)	(18.6	)%

Total Operating Costs Per Ton Sold	$	35.73	$	45.66	$	(9.93	)	(21.7	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.19		1.58		(0.39		)	(24.7	)%
Total Royalty/Production Taxes Per Ton Sold	3.23		4.44		(1.21		)	(27.3	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	8.23		9.46		(1.23		)	(13.0	)%
Total Costs Per VA Operations Ton Sold	$	48.38	$	61.14	$	(12.76	)	(20.9	)%
Average Margin Per VA Operations Ton Sold	$	9.38	$	9.85	$	(0.47	)	(4.8	)%

Coal Sales

VA Operations produced coal outside sales revenues were $ 63 million for the three months ended June 30, 2015 compared to $67 million for the three months ended June 30, 2014 . The $4 million decrease was attributable to a $13.23 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 $53 million for the three months ended June 30, 2015 , or $4 million lower than the $57 million for the three months ended June 30, 2014 . Total costs per VA Operations ton sold were $48.38 per ton in the three months ended June 30, 2015 compared to $61.14 per ton for the three months ended June 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 (Loss) Income" of this quarterly report for more information.

Other Costs And Expenses

Other costs, including certain administrative expenses and depreciation, depletion, and amortization, decreased $7 million in the three months ended June 30, 2015 compared to the three months ended June 30, 2014 . This decrease was primarily attributable to $11 million of income due to modifications made to the Pension and OPEB plans for active employees in September 2014 and retirees in May 2015. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income" of this quarterly report for more information. The remaining $4 million change included 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 June 30, 2015 compared to $2 million for the three months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

For the three months ended June 30, 2015 , other corporate expenses were $3 million compared to $2 million for the three months ended June 30, 2014 . The $1 million increase was due to various transactions that occurred throughout both periods, none of which were individually material.

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 June 30, 2015 and 2014 , the segment included the Miller Creek Complex.

The Other coal segment had a loss before income tax of $14 million for the three months ended June 30, 2015 , compared to a loss before income tax of $ 10 million for the three months ended June 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)	0.5		0.5		—			—	%
Average Sales Price Per Other Operations Ton Sold	$	60.84	$	59.99	$	0.85		1.4	%

Total Operating Costs Per Ton Sold	$	46.23	$	48.81	$	(2.58	)	(5.3	)%
Total Direct Administrative and Selling Costs Per Ton Sold	0.93		1.23		(0.30		)	(24.4	)%
Total Royalty/Production Taxes Per Ton Sold	5.10		4.98		0.12			2.4	%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	2.82		3.44		(0.62		)	(18.0	)%
Total Costs Per Other Operations Ton Sold	$	55.08	$	58.46	$	(3.38	)	(5.8	)%
Average Margin Per Other Operations Ton Sold	$	5.76	$	1.53	$	4.23		276.5	%

Coal Sales

Other produced coal outside sales revenues were $32 million for the three months ended June 30, 2015 and June 30, 2014 . The increase in average sales price per ton is a result of an increase of sales on existing higher priced contracts for the three months ended June 30, 2015 as compared to the three months ended June 30, 2014 .

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 June 30, 2015 . Purchased coal sales revenue totaled $3 million for the three months ended June 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 $ 6 million for the three months ended June 30, 2015 compared to $ 10 million for the three months ended June 30, 2014 .The decrease of $4 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 was $1 million for the three months ended June 30, 2015 compared to $ 3 million for the three months ended June 30, 2014 . The $2 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

Miscellaneous other income was $21 million for the three months ended June 30, 2015 compared to $25 million for the three months ended June 30, 2014 . The change is due to the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance
Equity in Earnings of Affiliates	$	2	$	7	$	(5	)
Rental Income	9		10		(1		)
Royalty Income	4		5		(1		)
Right of Way Sales	4		1		3
Other	2		2		—
Total Other Income	$	21	$	25	$	(4	)


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


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


•	Right of way sales increased $3 million due to additional revenue earned from the sale of several right of ways during the three months ended June 30, 2015 .


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

Gain on Sale of Assets

Gain on sale of assets increased $5 million in the period-to-period comparison, primarily a result of the loss recorded in connection with the sale of various longwall shields in the three months ended June 30, 2014.

Cost of Coal Sold

Total cost of coal sold attributable to the Other coal segment was $29 million for the three months ended June 30, 2015 , or $2 million lower than the $31 million for the three months ended June 30, 2014 . Total costs per Other Operations ton sold were $55.08 per ton for the three months ended June 30, 2015 compared to $58.46 per ton for the three months ended June 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 $ 45 million for the three months ended June 30, 2015 compared to $44 million for the three months ended June 30, 2014 . The increase of $1 million was due to the following items:



	For the Three Months Ended June 30,
	2015		2014		Variance
Closed and Idle Mines	$	12	$	5	$	7
Pension and OPEB Plan	3		—		3
Lease Rental Expense	7		7		—
Depreciation, Depletion & Amortization	7		8		(1		)
Coal Reserve Holding Costs	2		3		(1		)
Coal Terminal Operations	5		7		(2		)
Purchased Coal	—		4		(4		)
Other	9		10		(1		)
Total Other Costs	$	45	$	44	$	1

•

Closed and idle mine costs increased $7 million for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 . This was due to an $11 million increase 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 June 30, 2014 . The increase was offset, in part, by a reduction of $2 million in property taxes and $2 million in compliance expenses.


•	Pension and OPEB plan expense increased $3 million due to modifications made to the Pension and OPEB plans in September 2014 for active employees and May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income" of this quarterly report for more information.


•	Lease rental expense remained consistent in the period-to-period comparison.


•	Depreciation, depletion, and amortization decreased $1 million primarily due to fewer assets placed in service in the period-to-period comparison.


•	Coal reserve holding costs decreased $1 million due to various transactions 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.


•	Purchased coal costs decreased $4 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.


•	Other costs decreased $1 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 $1 million for the three months ended June 30, 2015 compared to $2 million for the three months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

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

Freight Expense

Freight expense was $1 million for the three months ended June 30, 2015 compared to $3 million for the three months ended June 30, 2014 . The decrease of $2 million was primarily due to decreased shipments under contracts where CONSOL Energy contractually provides transportation services.

OTHER DIVISION ANALYSIS for the three months ended June 30, 2015 compared to the three months ended June 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 $59 million for the three months ended June 30, 2015 compared to a loss before income tax of $169 million for the three months ended June 30, 2014 . The other division also includes a total Company income tax benefit of $ 292 million for the three months ended June 30, 2015 compared to income tax expense of $ 1 million for the three months ended June 30, 2014 .



	For the Three Months Ended June 30,
(in millions)	2015			2014			Variance			Percent Change
Sales—Outside	$	—		$	59		$	(59	)	(100.0	)%
Other Income	—			1			(1		)	(100.0	)%
Total Revenue	—			60			(60		)	(100.0	)%
Miscellaneous Operating Expense	14			92			(78		)	(84.8	)%
Depreciation, Depletion & Amortization	—			1			(1		)	(100.0	)%
Loss on Debt Extinguishment	—			74			(74		)	(100.0	)%
Interest Expense	45			62			(17		)	(27.4	)%
Total Costs	59			229			(170		)	(74.2	)%
Loss Before Income Tax	(59		)	(169		)	110			65.1	%
Income Tax	(292		)	1			(293		)	(29,300.0	)%
Net Loss	$	233		$	(170	)	$	403		237.1	%

There were no outside sales revenues from the other division for the three months ended June 30, 2015 compared to $59 million for the three months ended June 30, 2014 . The decrease of $59 million was primarily related to the divestiture of our industrial supplies subsidiary in December 2014.

There was no Other Income recognized for the three months ended June 30, 2015 compared to $1 million of Other Income for the three months ended June 30, 2014 . The decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Total other costs related to the other division were $59 million for the three months ended June 30, 2015 compared to $229 million for the three months ended June 30, 2014 . Other costs decreased due to the following items:



	For the Three Months Ended June 30,
(in millions)	2015		2014		Variance
Loss on Extinguishment of Debt	$	—	$	74	$	(74	)
Industrial Supplies	—		60		(60		)
Pension Settlement	—		21		(21		)
Interest Expense	45		62		(17		)
Revolver Modification Fees	—		3		(3		)
Bank Fees	4		4		—
Transaction Fees	5		—		5
Pension Expense	3		—		3
Other	2		5		(3		)
	$	59	$	229	$	(170	)


•	Loss on Extinguishment of Debt of $74 million was recognized in the three months ended June 30, 2014 related to the early extinguishment of debt due to the purchase of all the 8.00% senior notes that were due in 2017 at an average premium of 1.04%.


•	There were no Industrial Supplies costs in the three months ended June 30, 2015 and $60 million in the three months ended June 30, 2014 . The decrease is due to the divestiture of our industrial supplies subsidiary in December 2014.


•	Pension settlement is required when the lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. 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 $17 million in the period-to-period comparison primarily due to the partial payoff of the 2020 and 2021 bonds in March and April 2015 and the partial payoff of the 2017 and 2020 bonds in April and August 2014. The decrease in interest expense is also due to lower interest rates on the newly issued 2023 bonds in March 2015 and the 2022 bonds issued in April and August 2014.


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


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


•	Transaction fees of $5 million related to fees associated with various corporate initiatives including the recent thermal MLP. See Note 20 - Subsequent Events in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.


•	Actuarially-calculated amortization of $3 million was included in the Other Division in the three months ended June 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 (Loss) Income" of this quarterly report for more information.


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

Income Taxes:

The effective income tax rate was 32.6% for the three months ended June 30, 2015 compared to (5.1)% for the three months ended June 30, 2014 . The effective rates for the three months ended June 30, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The effective rate for the three months ended June 30, 2015 is the U.S. federal statutory rate of 35% plus the Company's blended effective state rate of 2.7%. Per FASB Accounting Standards Codification (ASC) 740 - Income Taxes, when the actual year to date ordinary loss of a company exceeds its anticipated ordinary loss for the fiscal year, the tax benefit recognized for the year to date period is limited to the amount that would be recognized if the year to date ordinary loss was the anticipated ordinary loss for the fiscal year.

As a result of closing the IRS audit in the three months ended March 31, 2014, CONSOL Energy was required to file amended state income tax returns. In the quarter ended June 30, 2014 the Company filed the required amended returns and realized a discrete state income tax charge of $5.1 million which was offset by a federal tax benefit of $1.8 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Three Months Ended June 30,
(in millions)	2015			2014			Variance			Percent Change
Total Company Earnings Before Income Tax	$	(895	)	$	(24	)	$	(871	)	(3,671.9	)%
Income Tax (Benefit) Expense	$	(292	)	$	1		$	(293	)	(29,300.0	)%
Effective Income Tax Rate	32.6		%	(5.1		)%	37.7		%

Results of Operations - Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014

Net (Loss) Income

CONSOL Energy reported a net loss of $ 524 million , or a loss of $ 2.29 per diluted share, for the six months ended June 30, 2015 , compared to net income of $ 91 million , or earnings of $ 0.39 per diluted share, for the six months ended June 30, 2014 .

The total Exploration and Production (E&P) division contributed a loss of $ 815 million before income taxes for the six months ended June 30, 2015 compared to $ 101 million of earnings before income taxes for the six months ended June 30, 2014 . Total E&P production was 147.1 Bcfe for the six months ended June 30, 2015 compared to 100.3 Bcfe for the six months ended June 30, 2014 . Included in the net loss was a 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 Six Months Ended June 30,
in thousands (unless noted)	2015		2014			Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	13,759		3,488			10,271			294.5	%
Sales Volume (Mbbls)	2,293		581			1,712			294.7	%
Gross Price ($/Bbl)	$	16.20	$	51.96		$	(35.76	)	(68.8	)%
Gross Revenue	$	37,193	$	30,196		$	6,997		23.2	%

Oil:
Sales Volume (MMcfe)	306		327			(21		)	(6.4	)%
Sales Volume (Mbbls)	51		55			(4		)	(7.3	)%
Gross Price ($/Bbl)	$	46.92	$	92.88		$	(45.96	)	(49.5	)%
Gross Revenue	$	2,393	$	5,058		$	(2,665	)	(52.7	)%

Condensate:
Sales Volume (MMcfe)	3,160		775			2,385			307.7	%
Sales Volume (Mbbls)	527		129			398			308.5	%
Gross Price ($/Bbl)	$	26.34	$	85.56		$	(59.22	)	(69.2	)%
Gross Revenue	$	13,870	$	11,054		$	2,816		25.5	%

GAS
Sales Volume (MMcf)	129,882		95,683			34,199			35.7	%
Sales Price ($/Mcf)	$	2.55	$	4.95		$	(2.40	)	(48.5	)%
Hedging Impact ($/Mcf)	$	0.56	$	(0.23	)	$	0.79		343.5	%
Gross Revenue including Hedging Impact	$	403,931	$	451,186		$	(47,255	)	(10.5	)%

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



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Average Sales Price (per Mcfe)	$	3.11	$	4.96	$	(1.85	)	(37.3	)%
Average Costs (per Mcfe)	2.97		3.53		(0.56		)	(15.9	)%
Margin	$	0.14	$	1.43	$	(1.29	)	(90.2	)%

Total E&P division Natural Gas, NGLs, and Oil outside sales revenues were $ 456 million for the six months ended June 30, 2015 compared to $ 496 million for the six months ended June 30, 2014 . The decrease was primarily due to the 37.3% decrease in average sales price per Mcfe, offset in part, by the 46.7% 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 62.1 Bcf of our produced gas sales volumes for the six months ended June 30, 2015 at an average gain of $1.17 per Mcf. These economic hedges represented approximately 76.4 Bcf of our produced gas sales volumes for the six months ended June 30, 2014 at an average loss of $0.29 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 35.7% increase in gas sales volumes in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 51.1% of natural gas and liquid sales volumes for the six months ended June 30, 2015 compared to 44.4% in the six months ended June 30, 2014 .


•	Depreciation, depletion and amortization decreased on a unit basis due to 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 the portion of production from higher investment cost segments continued to grow.


•	Lifting costs also decreased on 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, well site maintenance, and well site tending.

The total coal division contributed $161 million of earnings before income taxes for the six months ended June 30, 2015 compared to $235 million for the six months ended June 30, 2014 . The total coal division sold 15.5 million tons of coal produced from CONSOL Energy mines for the six months ended June 30, 2015 compared to 16.6 million tons for the six months ended June 30, 2014 .

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



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Average Sales Price per ton sold	$	58.61	$	64.26	$	(5.65	)	(8.8	)%
Average Cost of Goods Sold per ton	44.45		46.43		(1.98		)	(4.3	)%
Margin	$	14.16	$	17.83	$	(3.67	)	(20.6	)%

The lower average sales price per ton sold reflects a 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 4.8 million tons on the export market for the six months ended June 30, 2015 compared to 3.4 million tons for the six months ended June 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. 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.

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. G&A costs are excluded from the E&P and Coal unit costs above. G&A costs were $44 million for the six months ended June 30, 2015 compared to $57 million for the six months ended June 30, 2014 . G&A costs decreased due to the following items:



	For the Six Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Contributions	$	2	$	9	$	(7	)	(77.8	)%
Employee Wages and Related Expenses	22		22		—			—	%
Advertising and Promotion	3		3		—			—	%
Consulting and Professional Services	10		14		(4		)	(28.6	)%
Miscellaneous	7		9		(2		)	(22.2	)%
Total Company General and Administrative Expense	$	44	$	57	$	(13	)	(22.8	)%


•	Contributions decreased $7 million primarily due to a charitable contribution of $6 million to the Boy Scouts of America during the six months ended June 30, 2014. The remaining $1 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.


•	Employee wages and related expenses remained consistent in the period-to-period comparison.


•	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.


•	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 $5 million for the six months ended June 30, 2015 compared to expense of $80 million for the six months ended June 30, 2014 . The decrease of $85 million to total Company expense was primarily due to modifications made to the OPEB and Pension plans in September 2014 and May 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 six months ended June 30, 2015 compared to the six months ended June 30, 2014 :

The E&P division had a loss before income tax of $ 815 million for the six months ended June 30, 2015 compared to earnings before income tax of $ 101 million for the six months ended June 30, 2014 . Variances by individual E&P segment are discussed below.



	For the Six Months Ended													Difference to Six Months Ended
	June 30, 2015													June 30, 2014
(in millions)	Marcellus		Utica			CBM		Other Gas			Total E&P			Marcellus			Utica			CBM			Other Gas			Total E&P
Sales:
Produced	$	235	$	36		$	140	$	45		$	456		$	5		$	16		$	(36	)	$	(25	)	$	(40	)
Related Party	—		—			1		—			1			—			—			(1		)	—			(1		)
Total Outside Sales	235		36			141		45			457			5			16			(37		)	(25		)	(41		)
Unrealized Gain on Commodity Derivative Instruments	—		—			—		35			35			—			—			—			35			35
Production Royalty Interest	—		—			—		20			20			—			—			—			(25		)	(25		)
Purchased Gas	—		—			—		5			5			—			—			—			—			—
Miscellaneous Other Income	—		—			—		31			31			—			—			—			(6		)	(6		)
Gain on Sale of Assets	—		—			—		2			2			—			—			—			(4		)	(4		)
Total Revenue and Other Income	235		36			141		138			550			5			16			(37		)	(25		)	(41		)
Lifting	15		9			17		16			57			2			3			(2		)	(2		)	1
Ad Valorem, Severance, and Other Taxes	9		1			4		2			16			2			—			(2		)	(4		)	(4		)
Transportation, Gathering and Compression	88		13			49		16			166			46			12			(3		)	(1		)	54
Gas Direct Administrative, Selling & Other	16		3			5		4			28			(1		)	1			—			3			3
Depreciation, Depletion and Amortization	72		22			42		37			173			15			17			(2		)	—			30
General & Administration	—		—			—		30			30			—			—			—			(3		)	(3		)
Production Royalty Interest	—		—			—		16			16			—			—			—			(23		)	(23		)
Purchased Gas	—		—			—		4			4			—			—			—			—			—
Exploration and Other Costs	—		—			—		4			4			—			—			—			(3		)	(3		)
Other Corporate Expenses	—		—			—		867			867			—			—			—			820			820
Total Exploration and Production Costs	200		48			117		996			1,361			64			33			(9		)	787			875
Interest Expense	—		—			—		4			4			—			—			—			—			—
Total E&P Division Costs	200		48			117		1,000			1,365			64			33			(9		)	787			875
Earnings (Loss) Before Income Tax	$	35	$	(12	)	$	24	$	(862	)	$	(815	)	$	(59	)	$	(17	)	$	(28	)	$	(812	)	$	(916	)

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $35 million to the total Company earnings before income tax for the six months ended June 30, 2015 compared to $94 million of earnings before income tax for the six months ended June 30, 2014 .



	For the Six Months Ended June 30,
	2015		2014			Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	65.1		41.3			23.8			57.6	%
NGLs Sales Volumes (Bcfe)*	8.7		2.9			5.8			200.0	%
Condensate Sales Volumes (Bcfe)*	1.4		0.3			1.1			366.7	%
Total Marcellus Sales Volumes (Bcfe)*	75.2		44.5			30.7			69.0	%

Average Sales Price - Gas (Mcf)	$	2.58	$	5.04		$	(2.46	)	(48.8	)%
Derivative Impact - Gas (Mcf)	$	0.47	$	(0.19	)	$	0.66		347.4	%
Average Sales Price - NGLs (Mcfe)*	$	3.35	$	8.75		$	(5.40	)	(61.7	)%
Average Sales Price - Condensate (Mcfe)*	$	5.13	$	12.88		$	(7.75	)	(60.2	)%

Total Average Marcellus sales (per Mcfe)	$	3.12	$	5.16		$	(2.04	)	(39.5	)%
Average Marcellus lifting costs (per Mcfe)	0.20		0.30			(0.10		)	(33.3	)%
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)	1.16		0.94			0.22			23.4	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	0.21		0.37			(0.16		)	(43.2	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	0.96		1.28			(0.32		)	(25.0	)%
Total Average Marcellus costs (per Mcfe)	$	2.65	$	3.05		$	(0.40	)	(13.1	)%
Average Margin for Marcellus (per Mcfe)	$	0.47	$	2.11		$	(1.64	)	(77.7	)%

The Marcellus segment outside sales revenues were $ 235 million for the six months ended June 30, 2015 compared to $ 230 million for the six months ended June 30, 2014 . The $ 5 million increase is primarily due to a 69.0% increase in total volumes sold, offset in part by a 39.5% decrease in total average sales prices in the period-to-period comparison. The increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program. The decrease in Marcellus total average sales price was primarily the result of the $2.46 per Mcf decrease in gas market prices, along with a $0.16 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 $0.66 per Mcf increase resulting from various transactions from our hedging program. These economic hedges represented approximately 26.6 Bcf of our produced Marcellus gas sales volumes for the six months ended June 30, 2015 at an average gain of $1.14 per Mcf. For the six months ended June 30, 2014 , these economic hedges represented approximately 31.3 Bcf at an average loss of $0.25 per Mcf.

Total costs for the Marcellus segment were $200 million for the six months ended June 30, 2015 compared to $136 million for the six months ended June 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 $15 million for the six months ended June 30, 2015 compared to $13 million for the six months ended June 30, 2014 . The increase in total dollars primarily relates to an increase in contractual services related to well tending and repairs and maintenance. The increases were offset, in part, by a decrease in salt water disposal costs and a decrease in costs related to wells operated by our joint-venture partners. The decrease in unit costs was primarily due to the 69.0% increase in total sales volumes.

• Marcellus ad valorem, severance and other taxes were $9 million for the six months ended June 30, 2015 compared to $7 million for the six months ended June 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 $88 million for the six months ended June 30, 2015 compared to $42 million for the six months ended June 30, 2014 . The $ 46 million increase in total dollars primarily relates 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 200.0% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increase in unit costs due to the increase in total dollars was offset, in part, by the increase in gas sales volumes.

• Marcellus direct administrative, selling and other costs were $16 million for the six months ended June 30, 2015 compared to $ 17 million for the six months ended June 30, 2014 . Direct administrative, selling and other 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. Unit costs were positively impacted by the increase in gas sales volumes.

• Depreciation, depletion and amortization costs were $72 million for the six months ended June 30, 2015 compared to $57 million for the six months ended June 30, 2014 . These amounts included depreciation on a per unit basis of $0.95 per Mcf and $1.25 per Mcf, respectively. The remaining amount of 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 $12 million for the six months ended June 30, 2015 compared to earnings before income tax of $5 million for the six months ended June 30, 2014 .



	For the Six Months Ended June 30,
	2015			2014			Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	13.4			1.8			11.6			644.4	%
NGLs Sales Volumes (Bcfe)*	5.1			0.7			4.4			628.6	%
Condensate Sales Volumes (Bcfe)*	1.7			0.4			1.3			325.0	%
Total Utica Sales Volumes (Bcfe)*	20.2			2.9			17.3			596.6	%

Average Sales Price - Gas (Mcf)	$	1.59		$	4.82		$	(3.23	)	(67.0	)%
Derivative Impact - Gas (Mcf)	$	—		$	(0.13	)	$	0.13		100.0	%
Average Sales Price - NGLs (Mcfe)*	$	1.60		$	8.20		$	(6.60	)	(80.5	)%
Average Sales Price - Condensate (Mcfe)*	$	3.78		$	15.36		$	(11.58	)	(75.4	)%

Total Average Utica sales price (per Mcfe)	$	1.79		$	7.03		$	(5.24	)	(74.5	)%
Average Utica lifting costs (per Mcfe)	0.47			2.22			(1.75		)	(78.8	)%
Average Utica ad valorem, severance, and other taxes (per Mcfe)	0.04			0.26			(0.22		)	(84.6	)%
Average Utica transportation, gathering, and compression costs (per Mcfe)	0.65			0.51			0.14			27.5	%
Average Utica direct administrative, selling & other costs (per Mcfe)	0.17			0.58			(0.41		)	(70.7	)%
Average Utica depreciation, depletion and amortization costs (per Mcfe)	1.05			1.66			(0.61		)	(36.7	)%
Total Average Utica costs (per Mcfe)	$	2.38		$	5.23		$	(2.85	)	(54.5	)%
Average Margin for Utica (per Mcfe)	$	(0.59	)	$	1.80		$	(2.39	)	(132.8	)%

Utica outside sales revenues were $36 million for the six months ended June 30, 2015 compared to $20 million for the six months ended June 30, 2014 . The increase was primarily due to the 596.6% increase in total volumes sold and was offset, in part, by the 74.5% decrease in the total average sales price. The 17.3 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 $5.24 per Mcf decrease in average market prices. None of our produced Utica sales volumes were hedged for the six months ended June 30, 2015 , which improved our average sales price $ 0.13 per Mcf when compared to the six months ended June 30, 2014 . Economic hedges represented approximately 1.5 Bcf of produced Utica gas sales volumes at an average loss of $0.17 per Mcf for the six months ended June 30, 2014 .

Total costs for the Utica segment were $48 million for the six months ended June 30, 2015 compared to $15 million for the six months ended June 30, 2014 . The increase in total dollars and decrease in unit costs were all directly related to the 596.6% 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 $24 million to the total Company earnings before income tax for the six months ended June 30, 2015 compared to $52 million of earnings before income tax for the six months ended June 30, 2014 .



	For the Six Months Ended June 30,
	2015		2014			Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	37.7		39.5			(1.8		)	(4.6	)%

Average Sales Price - Gas (Mcf)	$	2.89	$	4.81		$	(1.92	)	(39.9	)%
Derivative Impact - Gas (Mcf)	$	0.86	$	(0.30	)	$	1.16		386.7	%

Total Average CBM sales price (per Mcf)	$	3.75	$	4.51		$	(0.76	)	(16.9	)%
Average CBM lifting costs (per Mcf)	0.46		0.48			(0.02		)	(4.2	)%
Average CBM ad valorem, severance, and other taxes (per Mcf)	0.10		0.17			(0.07		)	(41.2	)%
Average CBM transportation, gathering, and compression costs (per Mcfe)	1.31		1.31			—			—	%
Average CBM direct administrative, selling & other costs (per Mcf)	0.12		0.12			—			—	%
Average CBM depreciation, depletion and amortization costs (per Mcf)	1.11		1.12			(0.01		)	(0.9	)%
Total Average CBM costs (per Mcf)	$	3.10	$	3.20		$	(0.10	)	(3.1	)%
Average Margin for CBM (per Mcf)	$	0.65	$	1.31		$	(0.66	)	(50.4	)%

CBM outside sales revenues were $141 million in the six months ended June 30, 2015 compared to $178 million for the six months ended June 30, 2014 . The $37 million decrease was primarily due to a 16.9% decrease in the total average sales price per Mcf as well as a 4.6% 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 $1.92 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $1.16 per Mcf increase due to various transactions from our hedging program. These economic hedges represented approximately 26.8 Bcf of our produced CBM gas sales volumes for the six months ended June 30, 2015 at an average gain of $1.21 per Mcf. For the six months ended June 30, 2014 , these economic hedges represented approximately 35.2 Bcf at an average loss of $0.33 per Mcf.

Total costs for the CBM segment were $117 million for the six months ended June 30, 2015 compared to $126 million for the six months ended June 30, 2014 . The decrease in total dollars and unit costs for the CBM segment were due to the following items:

• CBM lifting costs were $17 million for the six months ended June 30, 2015 compared to $ 19 million for the six months ended June 30, 2014 . The decrease in total dollars was primarily related to a decrease in contractual services related to well tending and a decrease in salt water disposal 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 $4 million for the six months ended June 30, 2015 compared to $6 million for the six months ended June 30, 2014 . The decrease of $2 million was due to a decrease in severance tax expense resulting from the decrease in average sales price, without the impact of hedging, as described above. 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 $49 million for the six months ended June 30, 2015 compared to $52 million for the six months ended June 30, 2014 . The $ 3 million decrease in total dollars was primarily related to a decrease in repairs and maintenance. Unit costs remained consistent in the period-to-period comparison.

• CBM direct administrative, selling and other costs were $5 million for the six months ended June 30, 2015 and June 30, 2014 . Unit costs also remained consistent in the period-to-period comparison.

• Depreciation, depletion and amortization attributable to the CBM segment was $42 million for the six months ended June 30, 2015 compared to $44 million for the six months ended June 30, 2014 . These amounts included depreciation on a per unit basis of $0.73 per Mcf and $0.77 per Mcf, respectively. The remaining amount of 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 $862 million for the six months ended June 30, 2015 compared to a loss before income tax of $50 million for the six months ended June 30, 2014 .



	For the Six Months Ended June 30,
	2015			2014			Variance			Percent Change
Other Gas Sales Volumes (Bcf)	13.7			13.1			0.6			4.6	%
Oil Sales Volumes (Bcfe)*	0.3			0.3			—			—	%
Total Other Sales Volumes (Bcfe)*	14.0			13.4			0.6			4.5	%

Average Sales Price - Gas (Mcf)	$	2.41		$	5.11		$	(2.70	)	(52.8	)%
Derivative Impact - Gas (Mcf)	$	0.70		$	(0.19	)	$	0.89		468.4	%
Average Sales Price - Oil (Mcfe)*	$	7.96		$	15.25		$	(7.29	)	(47.8	)%

Total Average Other sales price (per Mcfe)	$	3.20		$	5.18		$	(1.98	)	(38.2	)%
Average Other lifting costs (per Mcfe)	1.06			1.25			(0.19		)	(15.2	)%
Average Other ad valorem, severance, and other taxes (per Mcfe)	0.17			0.44			(0.27		)	(61.4	)%
Average Other transportation, gathering, and compression costs (per Mcfe)	1.12			1.23			(0.11		)	(8.9	)%
Average Other direct administrative, selling & other costs (per Mcfe)	0.31			0.15			0.16			106.7	%
Average Other depreciation, depletion and amortization costs (per Mcfe)	2.52			2.66			(0.14		)	(5.3	)%
Total Average Other costs (per Mcfe)	$	5.18		$	5.73		$	(0.55	)	(9.6	)%
Average Margin for Other (per Mcfe)	$	(1.98	)	$	(0.55	)	$	(1.43	)	(260.0	)%

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 $45 million for six months ended June 30, 2015 compared to $70 million for the six months ended June 30, 2014 . The decrease in outside sales revenue primarily relates to the $ 1.98 per Mcf decrease in total average sales price. Total costs related to these other sales were $75 million for the six months ended June 30, 2015 compared to $79 million for the six months ended June 30, 2014 .

Unrealized gain on commodity derivative instruments represents changes in fair value of all existing gas commodity hedges on a mark-to-market basis. Unrealized gains on commodity derivative instruments increased $35 million due to the December 31, 2014 de-designation of all our derivative positions as hedging instruments. 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 $20 million for the six months ended June 30, 2015 compared to $45 million for the six months ended June 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 Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	10.9		9.1		1.8			19.8	%
Average Sales Price Per thousand cubic feet	$	1.85	$	4.95	$	(3.10	)	(62.6	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $5 million for the six months ended June 30, 2015 and June 30, 2014 .



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	1.4		0.7		0.7			100.0	%
Average Sales Price Per thousand cubic feet	$	3.53	$	7.23	$	(3.70	)	(51.2	)%

Miscellaneous other income was $31 million for the six months ended June 30, 2015 compared to $37 million for the six months ended June 30, 2014 . The $6 million decrease was primarily due to the following items:



	For the Six Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Gathering Revenue	$	8	$	21	$	(13	)	(61.9	)%
Equity in Earnings of Affiliates	18		13		5			38.5	%
Other	5		3		2			66.7	%
Total Miscellaneous Other Income	$	31	$	37	$	(6	)	(16.2	)%


•	Gathering revenue decreased $ 13 million primarily due to a decrease in revenue related to certain gathering arrangements.


•	Equity in Earnings of Affiliates increased $ 5 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.


•	The remaining $ 2 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.

Gain on sale of assets was $2 million for the six months ended June 30, 2015 compared to $6 million for the six months ended June 30, 2014 . The $4 million decrease was due to various transactions that occurred throughout both periods, none of which were individually significant.

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 $30 million for the six months ended June 30, 2015 compared to $33 million for the six months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report 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 $16 million for the six months ended June 30, 2015 compared to $39 million for the six months ended June 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 Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Production Royalty Interest Sales Volumes (in billion cubic feet)	10.9		9.1		1.8			19.8	%
Average Cost Per thousand cubic feet sold	$	1.44	$	4.26	$	(2.82	)	(66.2	)%

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 $4 million for the six months ended June 30, 2015 and June 30, 2014 .



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	1.4		0.7		0.7			100.0	%
Average Cost Per thousand cubic feet sold	$	2.77	$	5.89	$	(3.12	)	(53.0	)%

Exploration and other costs were $4 million for the six months ended June 30, 2015 compared to $7 million for the six months ended June 30, 2014 . The $ 3 million decrease is due to the following items:



	For the Six Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Land Rentals	$	2	$	2	$	—		—	%
Lease Expiration Costs	2		2		—			—	%
Other	—		3		(3		)	(100.0	)%
Total Exploration and Other Costs	$	4	$	7	$	(3	)	(42.9	)%


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


•	Lease expiration costs remained consistent in the period-to-period comparison.


•	The remaining $3 million decrease related to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $867 million for the six months ended June 30, 2015 compared to $47 million for the six months ended June 30, 2014 . The $820 million increase in the period-to-period comparison was made up of the following items:



	For the Six Months Ended June 30,
(in millions)	2015		2014		Variance			Percent Change
Impairment of Exploration and Production Properties	$	829	$	—	$	829		100.0	%
Idle Rig Fees	3		—		3			100.0	%
Stock-Based Compensation	8		10		(2		)	(20.0	)%
Unutilized Firm Transportation and Processing Fees	18		20		(2		)	(10.0	)%
Bank Fees	—		4		(4		)	(100.0	)%
Short-Term Incentive Compensation	6		11		(5		)	(45.5	)%
Other	3		2		1			50.0	%
Total Other Corporate Expenses	$	867	$	47	$	820		1,744.7	%


•	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 our natural gas rigs.


•	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 $ 2 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 increased $ 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 remained consistent at $4 million for the six months ended June 30, 2015 and June 30, 2014 .

TOTAL COAL DIVISION ANALYSIS for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 :

The coal division contributed $161 million of earnings before income tax for the six months ended June 30, 2015 compared to $235 million of earnings before income tax for the six months ended June 30, 2014 . Variances by the individual coal segment are discussed below.



	For the Six Months Ended											Difference to Six Months Ended
	June 30, 2015											June 30, 2014
(in millions)	Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal		Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal
Sales:
Produced Coal	$	703		$	144		$	62		$	909	$	(144	)	$	(8	)	$	(3	)	$	(155	)
Purchased Coal	—			—			2			2		—			—			(5		)	(5		)
Total Coal Sales	703			144			64			911		(144		)	(8		)	(8		)	(160		)
Other Outside Sales	—			—			20			20		—			—			(1		)	(1		)
Freight Revenue	5			—			5			10		(9		)	(1		)	—			(10		)
Miscellaneous Other Income	2			—			40			42		(34		)	—			(11		)	(45		)
Gain on Sale of Assets	—			—			3			3		(1		)	—			5			4
Total Revenue and Other Income	710			144			132			986		(188		)	(9		)	(15		)	(212		)
Cost of Coal Sold:
Operating Costs	403			76			46			525		(43		)	(24		)	(6		)	(73		)
Direct Administrative and Selling	13			2			1			16		(3		)	(1		)	(1		)	(5		)
Total Royalty/Production Taxes	29			8			6			43		(10		)	(1		)	1			(10		)
Depreciation, Depletion and Amortization	86			17			3			106		11			(2		)	—			9
Total Cost of Coal Sold:	531			103			56			690		(45		)	(28		)	(6		)	(79		)
Other Costs and Expenses:
Other Costs	(14		)	(4		)	79			61		(16		)	(9		)	(3		)	(28		)
Direct Administrative and Selling	—			—			1			1		(1		)	—			(1		)	(2		)
Total Royalty/Production taxes	—			—			2			2		—			—			1			1
Depreciation, Depletion and Amortization	5			6			14			25		—			1			(2		)	(1		)
Total Other Costs and Expenses:	(9		)	2			96			89		(17		)	(8		)	(5		)	(30		)
General and Administrative Expense	10			2			2			14		(3		)	(2		)	(4		)	(9		)
Other Corporate Expense	13			6			3			22		(9		)	—			(1		)	(10		)
Freight Expense	5			—			5			10		(9		)	(1		)	—			(10		)
Total Costs	550			113			162			825		(83		)	(39		)	(16		)	(138		)
Earnings (Loss) Before Income Taxes	$	160		$	31		$	(30	)	$	161	$	(105	)	$	30		$	1		$	(74	)

PENNSYLVANIA (PA) OPERATIONS COAL SEGMENT

The PA Operations coal segment's principal activities are 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 are therefore not included in unit cost presentation. For the six months ended June 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 $160 million to total Company earnings before income tax for the six months ended June 30, 2015 compared to $265 million of earnings before income tax for the six months ended June 30, 2014 . PA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Company Produced PA Operations Tons Sold (in millions)	12.2		13.4		(1.2		)	(9.2	)%
Average Sales Price Per PA Operations Ton Sold	$	57.61	$	62.98	$	(5.37	)	(8.5	)%

Total Operating Costs Per Ton Sold	$	33.16	$	33.00	$	0.16		0.5	%
Total Direct Administrative and Selling Costs Per Ton Sold	1.04		1.22		(0.18		)	(14.8	)%
Total Royalty/Production Taxes Per Ton Sold	2.32		2.91		(0.59		)	(20.3	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.94		5.64		1.30			23.0	%
Total Costs Per PA Operations Ton Sold	$	43.46	$	42.77	$	0.69		1.6	%
Average Margin Per PA Operations Ton Sold	$	14.15	$	20.21	$	(6.06	)	(30.0	)%

Coal Sales

PA Operations produced coal outside sales revenues were $703 million for the six months ended June 30, 2015 compared to $847 million for the six months ended June 30, 2014 . The $144 million decrease was attributable to a $5.37 per ton lower average sales price and a 1.2 million decrease in tons sold. The lower average coal sales price per ton sold in the 2015 period was primarily the result of the overall 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 (i.e. rail) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $5 million for the six months ended June 30, 2015 compared to $14 million for the six months ended June 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 $34 million in the period-to-period comparison due to a $30 million coal customer contract buyout and $4 million of various transactions, none of which were individually material. The discontinued contract was a long-term contract that created pricing risks for both parties. An amicable settlement was reached.

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 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 costs of coal sold per ton include 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 were $531 million for the six months ended June 30, 2015 , or $45 million lower than the $576 million for the six months ended June 30, 2014 . Total costs per PA Operations ton sold was $43.46 per ton for the six months

ended June 30, 2015 compared to $42.77 per ton for the six months ended June 30, 2014 . The decrease in total dollars was primarily due to the decrease of 1.2 million tons sold, while the increase in the unit cost was result of additional depreciation expense per unit as a result of Harvey Mine beginning production in March 2014

Other Costs And Expenses

Other costs is 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 expense and depreciation, depletion, and amortization, decreased $17 million for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily related to $24 million of income related 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 contained in the section "Net (Loss) Income" of this quarterly report 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 $1 million decrease is 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 activity at the segment determined by their level of operating activity. The amount of General and Administrative costs allocated to PA Operations was $10 million for the six months ended June 30, 2015 compared to $13 million for the six months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

Other corporate expense is made up of expenses for stock based compensation and the short-term incentive compensation program. These expenses are made up of 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 three months ended June 30, 2015 other corporate expenses were $13 million compared to $22 million for the three months ended June 30, 2014 . The decrease of $9 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 and the negotiated freight rates for rail transportation for customers to which we contractually provide transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. For the six months ended June 30, 2015 freight expense was $5 million compared to $14 million for the six months ended June 30, 2014 . The $9 million decrease was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

VIRGINIA (VA) OPERATIONS COAL SEGMENT

The VA Operations coal segment's principal activities are 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 six months ended June 30, 2015 and 2014 , the segment included Buchanan Mine and the corresponding preparation plant facilities.

The VA Operations coal segment contributed $31 million to total Company earnings before income tax for the six months ended June 30, 2015 compared to earnings before income tax of $1 million for the six months ended June 30, 2014 . The VA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Company Produced VA Operations Tons Sold (in millions)	2.3		2.0		0.3			15.0	%
Average Sales Price Per VA Operations Ton Sold	$	62.82	$	74.11	$	(11.29	)	(15.2	)%

Total Operating Costs Per Ton Sold	$	32.96	$	48.94	$	(15.98	)	(32.7	)%
Total Direct Administrative and Selling Costs Per Ton Sold	1.05		1.54		(0.49		)	(31.8	)%
Total Royalty/Production Taxes Per Ton Sold	3.61		4.51		(0.9		)	(20.0	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	7.60		8.98		(1.38		)	(15.4	)%
Total Costs Per VA Operations Ton Sold	$	45.22	$	63.97	$	(18.75	)	(29.3	)%
Average Margin Per VA Operations Ton Sold	$	17.60	$	10.14	$	7.46		73.6	%

Coal Sales

VA Operations produced coal outside sales revenues were $144 million for the six months ended June 30, 2015 compared to $152 million for the six months ended June 30, 2014 . The $8 million decrease was primarily attributable to an $11.29 per ton lower average sales price, offset, in part, by an increase of 0.3 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 weakening in the global metallurgical coal market.

Freight Revenue

There was no Freight Revenue for the six months ended June 30, 2015 . Freight revenue was $1 million for the six months ended June 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 $103 million for the six months ended June 30, 2015 , or $28 million lower than the $131 million for the six months ended June 30, 2014 . Total costs per VA Operations ton sold were $45.22 per ton in the six months ended June 30, 2015 compared to $63.97 per ton for the six months ended June 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 (Loss) Income" of this quarterly report for more information.

Other Costs And Expenses

Other costs, including certain administrative expense and depreciation, depletion, and amortization, were $ 2 million for the six months ended June 30, 2015 compared to $ 10 million for the six months ended June 30, 2014 . The $8 million decrease was primarily attributable to $13 million of income due to modifications made to the Pension and OPEB plans in September 2014 for

active employees and in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income" of this quarterly report for more information. The remaining $5 million change included 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 $2 million for the six months ended June 30, 2015 compared to $4 million for the six months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report 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 six months ended June 30, 2015 compared to $1 million for the six months ended June 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 six months ended June 30, 2015 and 2014 , the segment included the Miller Creek Complex.

The Other coal segment had a loss before income tax of $30 million for the six months ended June 30, 2015 compared to a loss before income tax of $31 million for the six months ended June 30, 2014 . Other coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Six Months Ended June 30,
	2015		2014		Variance			Percent Change
Company Produced Other Operations Tons Sold (in millions)	1.0		1.2		(0.2		)	(16.7	)%
Average Sales Price Per Other Operations Ton Sold	$	61.18	$	61.47	$	(0.29	)	(0.5	)%

Total Operating Costs Per Ton Sold	$	45.73	$	49.02	$	(3.29	)	(6.7	)%
Total Direct Administrative and Selling Costs Per Ton Sold	0.91		1.23		(0.32		)	(26.0	)%
Total Royalty/Production Taxes Per Ton Sold	5.12		5.18		(0.06		)	(1.2	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	2.88		3.45		(0.57		)	(16.5	)%
Total Costs Per Other Operations Ton Sold	$	54.64	$	58.88	$	(4.24	)	(7.2	)%
Average Margin Per Other Operations Ton Sold	$	6.54	$	2.59	$	3.95		152.5	%

Coal Sales

Other produced coal outside sales revenues were $62 million for the six months ended June 30, 2015 compared to $65 million for the six months ended June 30, 2014 . The $3 million decrease was attributable to a $0.29 per ton lower average sales price. The lower average coal sales price in the 2015 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. The revenues were $2 million for the six months ended June 30, 2015 compared to $7 million for the six months ended June 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 $ 20 million for the six months ended June 30, 2015 compared to $ 21 million for the six months ended June 30,

2014 . The $1 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 $40 million for the six months ended June 30, 2015 compared to $51 million for the six months ended June 30, 2014 . The change is due to the following items:



	For the Six Months Ended June 30,
(in millions)	2015		2014		Variance
Rental Income	$	18	$	24	$	(6	)
Equity in Earnings of Affiliates	5		10		(5		)
Royalty Income	8		10		(2		)
Right of Way Sales	5		2		3
Other	4		5		(1		)
Total Other Income	$	40	$	51	$	(11	)


•	Rental income decreased $6 million due to the buyout of certain equipment that was leased by CONSOL Energy and then subleased to a third-party in 2014.


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


•	Right of way sales increased $3 million due to additional revenue earned from the sale of several right of ways during the six months ended June 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 $5 million in the period-to-period comparison, primarily a result of the loss recorded in connection with the sale of various longwall shields for the six months ended June 30, 2014 .

Cost of Coal Sold

Total cost of coal sold attributable to the Other coal segment was $56 million for the six months ended June 30, 2015 , or $6 million lower than the $62 million for the six months ended June 30, 2014 . Total costs per Other Operations ton sold were $54.64 per ton for the six months ended June 30, 2015 compared to $58.88 per ton for the six months ended June 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 $96 million for the six months ended June 30, 2015 compared to $101 million for the six months ended June 30, 2014 . The decrease of $5 million was due to the following items:



	For the Six Months Ended June 30,
	2015		2014		Variance
Purchased Coal	$	1	$	11	$	(10	)
Lease Rental Expense	13		16		(3		)
Coal Terminal Operations	11		14		(3		)
Depreciation, Depletion & Amortization	14		16		(2		)
Coal Reserve Holding Costs	4		5		(1		)
Closed and Idle Mines	26		20		6
Pension and OPEB Plan	11		1		10
Other	16		18		$	(2	)
Total Other Costs	$	96	$	101	$	(5	)


•	Purchased coal costs decreased $10 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.


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


•	Coal terminal operations costs decreased $3 million due to decreased thru-put volumes in the current quarter.


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


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

•

Closed and idle mine costs increased $6 million primarily due to a $13 million increase in the asset retirement obligation expense related to a reduction of the asset retirement obligation at the Fola Mining Complex during the six months ended June 30, 2014 . The increase was offset, in part, by a reduction of $4 million in property taxes and $2 million in compliance expenses. The remaining decrease was due to various items that occurred throughout both periods, none of which were individually material.


•	Pension and OPEB plan expense increased $10 million due to modifications made to the Pension and OPEB plans in September 2014 for active employees and in May 2015 for retired employees. Refer to the discussion of total Company long-term liabilities contained in the section "Net (Loss) Income" of this quarterly report for more information.


•	Other decreased $2 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 $2 million for the six months ended June 30, 2015 compared to $6 million for the six months ended June 30, 2014 . Refer to the discussion of total Company general and administrative costs contained in the section "Net (Loss) Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses were $3 million for the six months ended June 30, 2015 compared to $4 million for the six months ended June 30, 2014 . The $1 million decrease 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 six months ended June 30, 2015 compared to the six months ended June 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 $187 million for the six months ended June 30, 2015 compared to a loss before income tax of $227 million for the six months ended June 30, 2014 . The other division also includes a total Company income tax benefit of $318 million for the six months ended June 30, 2015 compared to income tax expense of $10 million for the six months ended June 30, 2014 .



	For the Six Months Ended
(in millions)	2015			2014			Variance			Percent Change
Sales—Outside	$	—		$	116		$	(116	)	(100.0	)%
Other Income	2			3			(1		)	(33.3	)%
Total Revenue	2			119			(117		)	(98.3	)%
Miscellaneous Operating Expense	24			160			(136		)	(85.0	)%
Depreciation, Depletion & Amortization	—			1			(1		)	(100.0	)%
Loss on Debt Extinguishment	68			74			(6		)	(8.1	)%
Interest Expense	97			111			(14		)	(12.6	)%
Total Costs	189			346			(157		)	(45.4	)%
Loss Before Income Tax	(187		)	(227		)	40			17.6	%
Income Tax	(318		)	10			(328		)	(3,280.0	)%
Net Income (Loss)	$	131		$	(237	)	$	368		155.3	%

There were no outside sales revenues from the other division for the six months ended June 30, 2015 compared to $116 million for the six months ended June 30, 2014 . The decrease of $116 million was primarily related to the divestiture of our industrial supplies subsidiary in December 2014.

There was $2 million of other income recognized for the six months ended June 30, 2015 compared to $3 million of Other Income for the six months ended June 30, 2014 . The decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Total other costs related to the other division were $189 million for the six months ended June 30, 2015 compared to $346 million for the six months ended June 30, 2014 . Other costs decreased due to the following items:



	For the Six Months Ended
(in millions)	2015		2014		Variance
Industrial Supplies	$	—	$	118	$	(118	)
Pension Settlement	—		21		(21		)
Interest Expense	97		111		(14		)
Loss on Extinguishment of Debt	68		74		(6		)
Revolver Modification Fees	—		3		(3		)
Bank Fees	8		8		—
Transaction Fees	5		—		5
Pension Expense	8		—		8
Other	3		11		(8		)
	$	189	$	346	$	(157	)


•	There were no Industrial Supplies costs in the six months ended June 30, 2015 and $118 million in the six months ended June 30, 2014 . The decrease is due to the divestiture of our industrial supplies subsidiary in December 2014.


•	Pension settlement is required when the lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. 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 $14 million in the period-to-period comparison primarily due to the partial payoff of the 2020 and 2021 bonds in the six months ended June 30, 2015 and the partial payoff of the 2017 and 2020 bonds in April and August 2014. The decrease in interest expense is also due to lower interest rates on the newly issued 2023 bonds 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.

•

In the six months ended June 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 six months ended June 30, 2014 , CONSOL Energy purchased all of the 8% senior notes that were due 2017 at an average price equal to 104.0% resulting in a loss on debt extinguishment of $74 million .


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


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


•	Transaction fees of $5 million related to fees associated with various corporate initiatives including the recent thermal MLP. See Note 20 - Subsequent Events in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.


•	Actuarially-calculated amortization of $8 million was included in the Other Division in the six months ended June 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 (Loss) Income" of this quarterly report for more information.


•	Other corporate items decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 37.7% for the six months ended June 30, 2015 compared to 9.1% for the six months ended June 30, 2014 . The effective rates for the six months ended June 30, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The effective rate for the six months ended June 30, 2015 is the U.S. federal statutory rate of 35% plus the Company's blended effective state rate of 2.7%. Per FASB Accounting Standards Codification (ASC) 740 - Income Taxes, when the actual year to date ordinary loss of a company exceeds its anticipated ordinary loss for the fiscal year, the tax benefit recognized for the year to date period is limited to the amount that would be recognized if the year to date ordinary loss was the anticipated ordinary loss for the fiscal year.

For the six months ended June 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 six months ended June 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.



	For the Six Months Ended
(in millions)	2015			2014			Variance			Percent Change
Total Company Earnings Before Income Tax	$	(842	)	$	106		$	(948	)	(890.5	)%
Income Tax (Benefit) Expense	$	(318	)	$	10		$	(328	)	(3,280.0	)%
Effective Income Tax Rate	37.7		%	9.1		%	28.6		%

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. The interest coverage ratio was 4.65 to 1.00 at June 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 and accounts receivable securitization facility. The current ratio was 1.38 to 1.00 at June 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 June 30, 2015 , the facility had $ 1,058 million of borrowings outstanding and $ 237 million of letters of credit outstanding, leaving $ 705 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. The Amendment also permits the incurrence of a term loan facility up to an aggregate principal amount of $600 million 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 million at subsidiaries of the Company that own the metallurgical coal assets.

CONSOL Energy also has an accounts receivable securitization facility. On March 27, 2015, this facility was amended to allow the Company to receive, on a revolving basis, up to $100 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper or LIBOR rates plus a charge for administrative services paid to financial institutions. At June 30, 2015 , eligible accounts receivable totaled approximately $ 89 million. At June 30, 2015 , the borrowings outstanding totaled $ 39 million and $ 49 million of letters of credit were outstanding, leaving $1 million of unused capacity. Effective July 7, 2015, CONSOL Energy has terminated it accounts receivable facility.

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 $ 165 million at June 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 Six Months Ended June 30,
	2015			2014			Change
Cash flows from operating activities	$	294		$	557		$	(263	)
Cash used in investing activities	$	(672	)	$	(725	)	$	53
Cash provided by (used in) financing activities	$	211		$	(12	)	$	223

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


•	Net income decreased $615 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 $327 million related to changes in deferred taxes, a decrease of $35 million due to the unrealized gain on commodity derivative instruments and additional depreciation, depletion, and amortization of $38 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 $184 million in the period-to-period comparison due to:


◦	Gas segment capital expenditures decreased $31 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, as well as various transactions that occurred throughout both periods.

◦

Coal segment capital expenditures decreased $157 million. This was comprised of a $103 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 $37 million due to its completion in the first quarter of 2014. Capitalized interest decreased $10 million due to the completion of the Harvey Mine. The remaining $7 million decrease is due to various other projects that occurred throughout both periods.


◦	Other capital expenditures increased $4 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•

Proceeds from the sale of assets decreased $126 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 $9 million related to 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.

•

Cash used by equity affiliates increased $5 million due to an additional $38 million of capital contributions to CONE Midstream Partners, LP coupled with a decrease of $35 million in capital contributions to CONE Gathering, LLC in the period ended June 30, 2015 compared to the period ended June 30, 2014. Also contributing to the increase was $2 million less of distributions received from various equity partners in the period ended June 30, 2015 compared to the period ended June 30, 2014.

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


•	In the six months ended June 30, 2015, CONSOL Energy received $1,058 million of proceeds from the senior secured credit facility compared to payments on the facility of $12 million in the six months ended June 30, 2014.


•	In the six months ended June 30, 2015, CONSOL Energy had proceeds of $39 million under the accounts receivable securitization facility. There were no borrowings under this facility as of June 30, 2014.

•

In the six months ended June 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 six months ended June 30, 2014, CONSOL Energy had net proceeds from long-term borrowings of $16 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 six months ended June 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 June 30, 2014.


•	In the six months ended June 30, 2015, CONSOL Energy paid $18 million in debt issuance and financing fees related to the issuance of the 2023 bonds and other debt restructuring.


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

The following is a summary of our significant contractual obligations at June 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	$	106,657	$	79,708	$	6,802	$	968	$	194,135
Gas Firm Transportation and Processing	118,501		215,787		185,537		603,450		1,123,275
Long-Term Debt	4,196		6,365		75,835		2,477,382		2,563,778
Interest on Long-Term Debt	152,567		324,774		324,545		394,478		1,196,364
Capital (Finance) Lease Obligations	8,301		15,256		14,269		9,295		47,121
Interest on Capital (Finance) Lease Obligations	2,953		4,284		2,465		486		10,188
Operating Lease Obligations	104,840		171,666		68,375		76,959		421,840
Long-Term Liabilities—Employee Related (a)	93,369		161,986		177,011		507,866		940,232
Other Long-Term Liabilities (b)	282,756		238,108		75,145		348,979		944,988
Total Contractual Obligations (c)	$	874,140	$	1,217,934	$	929,984	$	4,419,863	$	7,441,921

_________________________

(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 June 30, 2015 , CONSOL Energy had total long-term debt and capital lease obligations of $ 2,611 billion outstanding, including the current portion of long-term debt of $ 13 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 are 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 are 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 are 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 are guaranteed by most of CONSOL Energy’s subsidiaries.


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


•	Advance royalty commitments of $ 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 $ 47 million of capital leases with a weighted average interest rate of 6.27% per annum.

At June 30, 2015 , CONSOL Energy had an aggregate principal amount of $ 1,058 billion in outstanding borrowings and approximately $ 237 million of letters of credit outstanding under the $ 2.0 billion senior secured revolving credit facility.

At June 30, 2015 , CONSOL Energy had an aggregate principal amount of $39 million in outstanding borrowings and $ 49 million of letters of credit outstanding under the accounts receivable securitization facility.

Total Equity and Dividends

CONSOL Energy had total equity of $4.7 billion at June 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 (See Note 20 - Subsequent Events in the Notes to the Unaudited Consolidated Financial Statements), CONSOL Energy will reduce 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
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. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.50 per share when our leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 4.01 to 1.00 and the cumulative credit was approximately $640 million at June 30, 2015 . 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 June 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 June 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 our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the consolidated balance sheet at June 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,” 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;


•	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 June 30, 2015, our open derivative instruments were in a net asset position with a fair value of $165 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at June 30, 2015 . A hypothetical 10 percent increase in future natural gas prices would affect pre-tax future earnings related to derivatives by $68 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2015 , CONSOL Energy had $2,611 billion aggregate principal amount of debt outstanding under fixed-rate instruments and $1,097 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 $1,058 million of borrowings at June 30, 2015 . A hypothetical 100 basis-point increase in the average rate for CONSOL Energy's revolving credit facility would affect pre-tax future earnings related to interest expense by $6 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 July 13, 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		39,326,408		39,326,408		78,652,816
Weighted Average Hedge Price per Mcf	N/A		N/A		$	3.87	$	3.87	$	3.87
2016 Fixed Price Volumes
Hedged Mcf	27,569,465		27,569,465		27,872,426		27,872,426		110,883,782
Weighted Average Hedge Price per Mcf	$	3.97	$	3.97	$	3.97	$	3.97	$	3.97
2017 Fixed Price Volumes
Hedged Mcf	10,049,181		10,160,839		10,272,497		10,272,497		40,755,014
Weighted Average Hedge Price per Mcf	$	3.22	$	3.22	$	3.22	$	3.22	$	3.22


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of June 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 eighth 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 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in the “Risk Factors” section in Item 1A in the Annual Report on Form 10-K for the year ended December 31, 2014, together with the following risks that have been amended and restated from the prior “Risk Factors” disclosed in the Form 10-K. These described risks are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our domestic coal sales and adversely affect our results of operations.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fine particulate matter and carbon dioxide when coal is burned. Complying with regulations on these emissions can be costly for electric power generators. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel could materially affect us. Recent EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal- fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. Examples are (i) implementation of Phase 1 of the Cross-State Air Pollution Rule (CSAPR) that began in May 2015 with implementation of Phase 2 planned to begin in 2017; and (ii) promulgation in 2011 of the Utility Maximum Achievable Control Technology (Utility MACT) rule, better known as the Mercury and Air Toxics Standard (MATS) rule, which included more stringent new source performance standards (NSPS) for particulate matter (PM), mercury, sulfur dioxide (SO2) and nitrogen oxides (NOX), for new and existing coal-fired power plants (amended in November 2014). On June 29, 2015, the U.S. Supreme Court rejected the EPA MATS rule, ruling that the agency unreasonably overlooked the costs associated with the regulation, and sent the rule back to the D.C. Circuit Court to determine whether to remand and allow EPA to address the rule's deficiencies or to vacate and nullify the rule,

On October 14, 2014, the EPA Clean Water Act Section 316(b) rulemaking went into effect which requires new and existing power plants, including coal and natural gas-fired plants to reduce fish mortality caused by their cooling water intake structures through either the installation of technologies or the reduction of intake velocity.

Apart from actual and potential regulation of emissions, waste water, and solid wastes from coal-fired plants, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.

On July 16, 2015, The Office of Surface Mining released a new draft of its Stream Buffer Zone Rule. We are in the process of evaluating the potential impacts of the proposal on our operations.

Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for natural gas and coal and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our natural gas and coal assets.

While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as the natural gas and coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by natural gas and coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the northeastern U.S. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (but has not been ratified by the United States ) was nominally extended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. The EPA, under the Climate Action Plan, has elected to regulate GHGs under the Clean Air Act (CAA) to limit emissions of carbon dioxide (CO2) from coal- and natural gas-fired power plants. On September 20, 2013 EPA re-proposed New Source Performance Standards (NSPS) for CO2 from new power plants and on June 2, 2014 EPA re-proposed NSPS for CO2 from existing and modified/reconstructed power plants, which rescinded the rules that were originally proposed in 2012. EPA announced it will issue the final rules for existing and new power plants mid-summer 2015. On October 28, 2014, EPA also issued a supplemental proposal to the Clean Power Plan to address carbon pollution from affected power plants in Indian Country and U.S. territories.

Apart from governmental regulation, investment banks both domestically and internationally based have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants. In addition, banks have also adopted more stringent lending requirements of surface coal operations which may make it more difficult to obtain financing by coal operators.

Adoption of comprehensive legislation or regulation focusing on GHG emission reductions for the United States or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.

In January 2015 the EPA outlined a strategy for reducing methane and ozone-forming pollution from the oil and natural gas industry. This strategy includes potential requirements for emission reductions and mitigation techniques that target methane and volatile organic compounds (VOCs) that include methane. It is the current Administration’s goal to cut methane emissions from the oil and gas industry sector by 40 -45 percent from 2012 levels by 2025. The details of how EPA intends to reach the administrations goals are not currently known and so the potential impact to the oil and natural gas industry is difficult to ascertain. On April 14, 2015 the EPA released for external peer review five technical white papers on potentially significant sources of emissions in the oil and natural gas sector. The white papers focused on technical issues covering emissions and mitigation techniques that target methane and volatile organic compounds (VOCs). The EPA is expected to introduce a methane gas emissions limit in the summer of 2015.

Additionally, coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane has a greater GHG effect than carbon dioxide. Our natural gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methane emissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production.

Environmental Regulations introduce uncertainty that could adversely impact the market for natural gas and coal with potential short and long-term liabilities.

The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on species that have been identified and the current application of endangered species laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to produce gas or mine coal from our properties. However, In April 2015 the US Fish and Wildlife Service (USFWS) announced a Section 4(d) threatened listing final rule for the Northern Long-Eared Bat throughout our operations area. This listing will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Long-Eared bat, which is due to a disease commonly referred to as White Nose Syndrome (WNS). This listing could lead to significant timing and critical path hurdles, ultimately limiting the ability to clear timber for construction activities.

In April 2015 the USFWS also proposed the listing of Big Sandy Crayfish and Guyandotte River Crayfish as endangered under the ESA. USFWS has stated that the primary threats to crayfishes throughout their respective ranges are land-disturbing activities that increase erosion and sedimentation, which degrades the stream habitat required by both species. Identified sources of ongoing erosion and sedimentation that occur throughout the ranges of the species include active surface coal mining, commercial forestry, unpaved roads, gas and oil development, and road construction. This has the potential to disrupt future mining and natural gas activities in Central Appalachia.

In response to a spill by Freedom Industries of crude 4-methylcyclohexanemethanol (MCHM) to the Elk River in January 2014, West Virginia (WV) signed into law Senate Bill 373 (also known as the Above Ground Storage Tank Act), which requires

that all above ground storage tanks (ASTs) be registered with the Department of Environmental Protection (DEP) and meet additional requirements. This Act took effect on June 6, 2014. In October 2014 WV DEP filed a Final Interpretive Rule (47CSR62) addressing initial inspection, certification and spill prevention response plan requirements. On March 14, 2015, the WV Legislature passed Senate Bill 423 to amend the “unintended consequences” of the AST Act on the economy of WV which became effective June 12, 2015. However, with over 4,000 impacted ASTs currently operational in WV and more needed for oil and gas production, this proposed final rule could still have significant cost associated with its requirements. On June 25, 2015 the DEP proposed three AST rules to cover establishment of regulatory program, fees, and enforcement authority. The DEP plans issue a final rule to be effective in 2016.

The Company’s gas, water, and coal businesses must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that are unavoidable. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking known as the WOTUS rule that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal Waters of the U.S. On June 29, 2015 the EPA published the final WOTUS Rule which becomes effective on August 28, 2015. This rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs, add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under resourced, and lead to additional mitigation cost and severely limit CONSOL Energy’s ability to avoid regulated jurisdictional waters.

Management and regulation of point source discharges covered under the National Pollutant Discharge Eliminations System (NDEPES) of the CWA have undergone recent changes and proposed changes at both the state and federal level that have the potential to affect the long term treatment and discharge of water from coal mines. States are required by the CWA to conduct a comprehensive review of the state water quality standards every three years (the "Triennial Review").WV has issued an emergency rule effective June 21, 2014 and proposed amendments under 47 CSR 2 with specific requirements for the discharge of aluminum and selenium that pose potential impacts on the coal industry. Ohio (OH) is currently reviewing the current 401 and 404 permitting program to propose new amendments.

In April 2015, the EPA proposed a CWA regulation (Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category) establishing pretreatment standards that would prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (POTWs). While discharges to POTWs are not currently utilized, unconventional oil and gas extraction wastewater can be generated in large quantities. It's unclear how the newly proposed rule could affect future water use and disposal practices.

Federal and state regulations for horizontal well drilling and well site construction have been proposed and are currently being considered. On April 4, 2015 PA published an advanced notice of final rulemaking on revisions to the Environmental Protection Performance Standards at Oil and Gas Well Sites (Chapters 78 and 78a) that could have significant impacts on how oil and natural gas companies currently operate in PA. On June 26, 2015 WV proposed amendments to regulations under 35 WVCSR 8 regarding standards for Horizontal Well Development. In May 2015 OH passed Horizontal Well Site Construction Rules which will become effective in July 2015. OH is also in the process of reviewing and possibly adopting additional developing additional horizontal development rules.

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

The passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas, oil or coal exploration and development. Any such change could negatively affect our financial condition and results of operations.

In February 2012, the PA state legislature passed a new natural gas impact fee in PA, where a substantial portion of our acreage in the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average New York Mercantile Exchange’s natural gas prices from the last day of each month. The estimated total fees per well based on today’s current natural gas price is $310,000 over the 15 year period. The passage of this legislation increases the financial burden on our operations in the Marcellus Shale.

Additionally, legislation has been proposed in OH and PA to introduce a new severance tax on the oil and gas industry. The proposed rates have varied from 2.5 - 7.5 percent and would represent a significant increased financial burden beyond what is already in place.

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

The following table sets forth repurchases of our common stock during the six months ended June 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 5.	OTHER INFORMATION

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On Friday, July 31, 2015, the Compensation Committee of the Board of Directors of CONSOL Energy approved amendments to the change in control severance agreements of three executives in order to keep management focused on maximizing shareholder value and to reduce the distraction that any potential transaction might have on their respective personal situations. The agreements generally provide severance benefits to our executives only in the event that their employment is terminated after, or in connection with, a Change in Control (as defined in the their agreements) for any reason other than cause, death or disability, that occurs not more than three months prior to or within two years after, a Change in Control, or is requested by a third party initiating the Change in Control. To protect CONSOL Energy’s business interests, the agreements also contain confidentiality obligations, as well as non-competition and non-solicitation covenants. The amendments to these agreements are described below:

The Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL Energy and Mr. James A. Brock, the Chief Operating Officer - Coal of CONSOL Energy and the Chief Executive Officer of CNX Coal Resources GP LLC, CONSOL Energy’s wholly owned subsidiary and the general partner of CNX Coal Resources LP, the thermal coal master limited partnership (the MLP), was amended to add the following as Change in Control events: (i) a change in control of CNX Coal Resources GP LLC, and (ii) the sale of all or substantially all of the Pennsylvania Operations within the Coal Division, except to the extent such assets are the subject of a drop down into the MLP.

The Change in Control Severance Agreement, dated as of February 28, 2014, between CONSOL Energy and Mr. Timothy Dugan, the Chief Operating Officer - Exploration and Production of CONSOL Energy and the President and Chief Executive Officer of CNX Gas Corporation, was amended to include as a Change in Control event the Change in Control of CNX Gas Corporation.

The Amended and Restated Change in Control Severance Agreement, dated as of April 10, 2014, between CONSOL Energy and Mr. David M. Khani, Executive Vice President & Chief Financial Officer of CONSOL Energy, was amended to provide that, in the event of an Involuntary Termination Associated With a Change in Control, as that term is defined in the agreement, and subject to Mr. Khani’s compliance with the terms and conditions of the agreement, CONSOL Energy will pay him a lump sum cash severance payment equal to 2.5 (formerly 2.0) times base pay and bonus. Additionally, health benefits would be continued, and he would receive payments for retirement and pension benefits as if he had continued employment, for 30 months (formerly 24 months) under the agreement.


ITEM 6.	EXHIBITS



10.1			Amendment No. 1, dated as of May 22, 2015, to the Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the subsidiary guarantors party thereto and certain lenders and PNC Bank, National Association as administrative agent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 26, 2015.

10.2			Payoff and Termination Letter re: Amended and Restated Receivables Purchase Agreement, dated as of July 7, 2015, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank.

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

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

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

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

95			Mine Safety and Health Administration Safety Data.

101			Interactive Data File (Form 10-Q for the quarterly period ended June 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: July 31, 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)

TABLE OF CONTENTS

Part I : Financial Information Item 1. Condensed Financial Statements Note 1 Basis Of Presentation:Note 2 Acquisitions and Dispositions:Note 3 Miscellaneous Other Income:Note 4 Components Of Pension and Other Post-employment Benefit (opeb) Plans Net Periodic Benefit Costs:Note 5 Components Of Coal Workers Pneumoconiosis (cwp) and Workers Compensation Net Periodic Benefit Costs:Note 6 Income Taxes:Note 7 Inventories:Note 8 Accounts Receivable Securitization:Note 9 Property, Plant and Equipment:Note 10 Short-term Notes Payable:Note 11 Long-term Debt:Note 12 Commitments and Contingent Liabilities:Note 13 Derivative Instruments:Note 14 Fair Value Of Financial Instruments:Note 15 Segment Information:Note 16 Guarantor Subsidiaries Financial Information:Note 17 Related Party Transactions:Note 18 Stock Repurchase:Note 19 Recent Accounting Pronouncements:Note 20 Subsequent Event:Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part Ii: Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

CNX 10-Q Quarter ended June 30, 2015