CNX Resources Corp - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - CNX Resources Corp	Financial_Report.xls
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 - CNX Resources Corp	cnx-63014xex311.htm
EX-32.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - CNX Resources Corp	cnx63014-ex322.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 - CNX Resources Corp	cnx-63014xex312.htm
EX-95 - MINE SAFETY AND HEALTH ADMINISTRATION SAFETY DATA. - CNX Resources Corp	exhibit95msha63014.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350 - CNX Resources Corp	cnx63014-ex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended June 30, 2014



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 16, 2014
Common stock, $0.01 par value		230,166,816

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, 2014 and 2013.	3
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013.	4
	Consolidated Balance Sheets at June 30, 2014 and December 31, 2013.	5
	Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2014.	7
	Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013.	8
	Notes to Unaudited Consolidated Financial Statements	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	88

ITEM 4.	Controls and Procedures	89

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	89

ITEM 1A.	RISK FACTORS	89

ITEM 4.	Mine Safety Disclosures	90

ITEM 6.	Exhibits	91

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:	2014			2013			2014			2013
Natural Gas, NGLs and Oil Sales	$	229,743		$	171,236		$	496,041		$	339,078
Coal Sales	536,298			505,060			1,070,979			1,052,969
Other Outside Sales	70,087			65,218			139,374			133,902
Gas Royalty Interests and Purchased Gas Sales	19,739			18,434			49,958			33,996
Freight-Outside Coal	10,109			9,660			20,054			21,913
Miscellaneous Other Income	69,977			28,520			125,031			56,907
Gain on Sale of Assets	1,417			30,039			5,086			32,345
Total Revenue and Other Income	937,370			828,167			1,906,523			1,671,110
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	26,374			25,221			55,617			47,235
Transportation, Gathering and Compression	57,796			48,871			111,578			97,303
Production, Ad Valorem, and Other Fees	10,145			7,409			20,331			11,978
Direct Administrative and Selling	13,503			11,803			25,156			22,889
Depreciation, Depletion and Amortization	71,499			52,846			143,228			105,834
Exploration and Production Related Other Costs	4,624			10,406			7,723			20,895
Production Royalty Interests and Purchased Gas Costs	16,672			14,595			42,768			27,360
Other Corporate Expenses	21,012			22,557			47,176			47,950
General and Administrative	15,517			10,472			32,881			19,062
Total Exploration and Production Costs	237,142			204,180			486,458			400,506
Coal Costs
Operating and Other Costs	347,541			329,934			674,390			664,949
Royalties and Production Taxes	27,603			26,438			54,091			54,877
Direct Administrative and Selling	11,816			12,252			23,110			23,136
Depreciation, Depletion and Amortization	65,086			55,247			121,149			112,437
Freight Expense	10,109			9,660			20,054			21,913
General and Administrative Costs	10,450			10,038			22,963			19,339
Other Corporate Expenses	12,035			11,996			31,330			31,911
Total Coal Costs	484,640			455,565			947,087			928,562
Other Costs
Miscellaneous Operating Expense	99,079			73,872			173,628			196,908
General and Administrative Costs	428			470			834			893
Depreciation, Depletion and Amortization	1,314			1,436			2,638			2,836
Loss on Debt Extinguishment	74,277			—			74,277			—
Interest Expense	64,211			54,517			115,142			107,894
Total Other Costs	239,309			130,295			366,519			308,531
Total Costs And Expenses	961,091			790,040			1,800,064			1,637,599
(Loss) Earnings Before Income Tax	(23,721		)	38,127			106,459			33,511
Income Taxes	1,214			29,565			9,703			28,673
(Loss) Income From Continuing Operations	(24,935		)	8,562			96,756			4,838
(Loss) Income From Discontinued Operations, net	—			(21,375		)	(5,687		)	(19,472		)
Net (Loss) Income	(24,935		)	(12,813		)	91,069			(14,634		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(287		)	—			(544		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(24,935	)	$	(12,526	)	$	91,069		$	(14,090	)

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)	2014			2013			2014			2013
(Loss) Earnings Per Share
Basic
(Loss) Income from Continuing Operations	$	(0.11	)	$	0.04		$	0.42		$	0.02
Loss from Discontinued Operations	—			(0.09		)	(0.02		)	(0.08		)
Total Basic (Loss) Earnings Per Share	$	(0.11	)	$	(0.05	)	$	0.40		$	(0.06	)
Dilutive
(Loss) Income from Continuing Operations	$	(0.11	)	$	0.04		$	0.42		$	0.02
Loss from Discontinued Operations	—			(0.09		)	(0.03		)	(0.08		)
Total Dilutive (Loss) Earnings Per Share	$	(0.11	)	$	(0.05	)	$	0.39		$	(0.06	)

Dividends Paid Per Share	$	0.0625		$	0.125		$	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)	2014			2013			2014			2013
Net (Loss) Income	$	(24,935	)	$	(12,813	)	$	91,069		$	(14,634	)
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $2,214, ($26,489), ($771), ($54,739))	(3,798		)	42,904			1,321			88,661
Net (Decrease) Increase in the Value of Cash Flow Hedges (Net of tax: $8,027, ($29,484), $38,883, ($17,500))	(12,218		)	45,749			(59,183		)	27,154
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: ($6,642), $8,560, ($17,593), $22,526)	6,951			(9,528		)	23,264			(32,241		)

Other Comprehensive (Loss) Income	(9,065		)	79,125			(34,598		)	83,574

Comprehensive (Loss) Income	(34,000		)	66,312			56,471			68,940

Less: Comprehensive Loss Attributable to Noncontrolling Interest	—			(287		)	—			(544		)

Comprehensive (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(34,000	)	$	66,599		$	56,471		$	69,484

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, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and Cash Equivalents	$	147,393	$	327,420
Accounts and Notes Receivable:
Trade	275,431		332,574
Notes Receivable	1,328		25,861
Other Receivables	390,484		243,973
Inventories	148,005		157,914
Deferred Income Taxes	137,716		211,303
Recoverable Income Taxes	47,060		10,705
Prepaid Expenses	78,438		135,842
Total Current Assets	1,225,855		1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	14,160,967		13,578,509
Less—Accumulated Depreciation, Depletion and Amortization	4,384,209		4,136,247
Total Property, Plant and Equipment—Net	9,776,758		9,442,262
Other Assets:
Investment in Affiliates	352,187		291,675
Notes Receivable	—		125
Other	211,847		214,013
Total Other Assets	564,034		505,813
TOTAL ASSETS	$	11,566,647	$	11,393,667

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, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	504,009		$	514,580
Current Portion of Long-Term Debt	12,127			11,455
Other Accrued Liabilities	554,476			565,697
Current Liabilities of Discontinued Operations	13,054			28,239
Total Current Liabilities	1,083,666			1,119,971
Long-Term Debt:
Long-Term Debt	3,214,913			3,115,963
Capital Lease Obligations	44,468			47,596
Total Long-Term Debt	3,259,381			3,163,559
Deferred Credits and Other Liabilities:
Deferred Income Taxes	291,928			242,643
Postretirement Benefits Other Than Pensions	959,034			961,127
Pneumoconiosis Benefits	111,519			111,971
Mine Closing	320,902			320,723
Gas Well Closing	180,097			175,603
Workers’ Compensation	73,406			71,468
Salary Retirement	58,962			48,252
Reclamation	35,779			40,706
Other	132,315			131,355
Total Deferred Credits and Other Liabilities	2,163,942			2,103,848
TOTAL LIABILITIES	6,506,989			6,387,378
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 230,165,816 Issued and Outstanding at June 30, 2014; 229,145,736 Issued and Outstanding at December 31, 2013	2,305			2,294
Capital in Excess of Par Value	2,405,728			2,364,592
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	3,011,340			2,964,520
Accumulated Other Comprehensive Loss	(359,715		)	(325,117		)
Total CONSOL Energy Inc. Stockholders’ Equity	5,059,658			5,006,289
TOTAL LIABILITIES AND EQUITY	$	11,566,647		$	11,393,667

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY



(Dollars in thousands, except per share data)	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total CONSOL Energy Inc. Stockholders’ Equity
December 31, 2013	$	2,294	$	2,364,592	$	2,964,520		$	(325,117	)	$	5,006,289
(Unaudited)
Net Income	—		—		91,069			—			91,069
Other Comprehensive Loss	—		—		—			(34,598		)	(34,598		)
Comprehensive Income (Loss)	—		—		91,069			(34,598		)	56,471
Issuance of Common Stock	11		13,223		—			—			13,234
Treasury Stock Activity	—		—		(15,516		)	—			(15,516		)
Tax Benefit From Stock-Based Compensation	—		2,413		—			—			2,413
Amortization of Stock-Based Compensation Awards	—		25,500		—			—			25,500
Dividends ($0.125 per share)	—		—		(28,733		)	—			(28,733		)
Balance at June 30, 2014	$	2,305	$	2,405,728	$	3,011,340		$	(359,715	)	$	5,059,658

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:	2014			2013
Net Income (Loss)	$	91,069		$	(14,634	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Continuing Operating Activities:
Net Loss from Discontinued Operations	5,687			19,472
Depreciation, Depletion and Amortization	267,015			221,107
Stock-Based Compensation	25,500			34,647
Gain on Sale of Assets	(5,086		)	(32,345		)
Loss on Debt Extinguishment	74,277			—
Deferred Income Taxes	13,785			6,998
Equity in Earnings of Affiliates	(21,512		)	(16,667		)
Changes in Operating Assets:
Accounts and Notes Receivable	(52,920		)	25,360
Inventories	9,909			19,772
Prepaid Expenses	24,529			25,359
Changes in Other Assets	13,427			28,070
Changes in Operating Liabilities:
Accounts Payable	53,371			(13,470		)
Accrued Interest	(10,483		)	(73		)
Other Operating Liabilities	74,714			(4,173		)
Other	14,737			6,523
Net Cash Provided by Continuing Operations	578,019			305,946
Net Cash (Used in) Provided by Discontinued Operating Activities	(20,872		)	87,444
Net Cash Provided by Operating Activities	557,147			393,390
Cash Flows from Investing Activities:
Capital Expenditures	(819,295		)	(707,452		)
Change in Restricted Cash	—			68,673
Proceeds from Sales of Assets	133,075			107,626
Net Investments In Equity Affiliates	(39,000		)	(16,600		)
Net Cash Used in Investing Activities in Continuing Operations	(725,220		)	(547,753		)
Net Cash Provided By Investing Activities in Discontinued Operations	—			82,627
Net Cash Used in Investing Activities	(725,220		)	(465,126		)
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	(11,736		)	173,000
Payments on Miscellaneous Borrowings	(3,167		)	(29,964		)
Proceeds from Long-Term Borrowings	1,600,000			—
Payments on Long-Term Borrowings	(1,583,965		)	—
Proceeds from Securitization Facility	—			2,873
Tax Benefit from Stock-Based Compensation	2,413			2,185
Dividends Paid	(28,733		)	(28,601		)
Issuance of Common Stock	13,234			2,497
Net Cash (Used in) Provided By Financing Activities in Continuing Operations	(11,954		)	121,990
Net Cash Used in Financing Activities in Discontinued Operations	—			(198		)
Net Cash (Used in) Provided By Financing Activities	(11,954		)	121,792
Net (Decrease) Increase in Cash and Cash Equivalents	(180,027		)	50,056
Cash and Cash Equivalents at Beginning of Period	327,420			21,862
Cash and Cash Equivalents at End of Period	$	147,393		$	71,918

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, 2014 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2013 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, 2013 included in CONSOL Energy Inc.'s Form 10-K.

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2013, with no effect on previously reported net income or stockholders' equity.

Basic earnings per share are computed by dividing net income (loss) attributable to shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, CONSOL stock units, and restricted and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units, performance share units, and CONSOL 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,
	2014	2013	2014	2013
Anti-Dilutive Options	4,123,949	4,845,029	359,488	4,845,029
Anti-Dilutive Restricted Stock Units	1,265,237	1,383,908	—	1,383,908
Anti-Dilutive Performance Share Units	523,357	83,356	—	83,356
Anti-Dilutive Performance Share Options	802,804	602,101	—	602,101
	6,715,347	6,914,394	359,488	6,914,394

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,
	2014	2013	2014	2013
Options	382,773	160,119	648,112	245,113
Restricted Stock Units	56,403	89,632	390,802	568,141
Performance Share Units	—	—	378,971	159,228
	439,176	249,751	1,417,885	972,482

The weighted average exercise price per share of the options exercised during the three months ended June 30, 2014 and 2013 was $21.57 and $9.90, respectively. The weighted average exercise price per share of the options exercised during the six months ended June 30, 2014 and 2013 was $20.41 and $10.16, respectively.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
(Loss) Income from Continuing Operations	$	(24,935	)	$	8,562		$	96,756		$	4,838
(Loss) Income from Discontinuing Operations	—			(21,375		)	(5,687		)	(19,472		)
Less: Net Loss Attributable to Noncontrolling Interest	—			(287		)	—			(544		)
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(24,935	)	$	(12,526	)	$	91,069		$	(14,090	)
Weighted average shares of common stock outstanding:
Basic	230,061,395			228,721,980			229,795,193			228,520,886
Effect of stock-based compensation awards	—			—			1,595,988			—
Dilutive	230,061,395			228,721,980			231,391,181			228,520,886
Earnings per share:
Basic (Continuing Operations)	$	(0.11	)	$	0.04		$	0.42		$	0.02
Basic (Discontinuing Operations)	—			(0.09		)	(0.02		)	(0.08		)
Total Basic	$	(0.11	)	$	(0.05	)	$	0.40		$	(0.06	)

Dilutive (Continuing Operations)	$	(0.11	)	$	0.04		$	0.42		$	0.02
Dilutive (Discontinuing Operations)	—			(0.09		)	(0.03		)	(0.08		)
Total Dilutive	$	(0.11	)	$	(0.05	)	$	0.39		$	(0.06	)

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



	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2013	$	42,493		$	(367,610	)	$	(325,117	)
Other comprehensive income before reclassifications	(59,183		)	(22,133		)	(81,316		)
Amounts reclassified from accumulated other comprehensive income	23,264			23,454			46,718
Current period other comprehensive income	(35,919		)	1,321			(34,598		)
Balance at June 30, 2014	$	6,574		$	(366,289	)	$	(359,715	)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Derivative Instruments (Note 13)
Natural gas price swaps and options	$	13,593		$	(18,088	)	$	40,857		$	(54,767	)
Tax (expense) benefit	(6,642		)	8,560			(17,593		)	22,526
Net of tax	$	6,951		$	(9,528	)	$	23,264		$	(32,241	)
Actuarially Determined Long-Term Liability Adjustments*(Note 4 and Note 5)
Amortization of prior service costs	$	(2,542	)	$	(8,211	)	$	(5,084	)	$	(16,423	)
Recognized net actuarial loss	10,861			23,559			21,507			48,747
Settlement loss	20,707			5,087			20,707			32,202
Total	29,026			20,435			37,130			64,526
Tax expense	(10,691		)	(7,800		)	(13,676		)	(24,631		)
Net of tax	$	18,335		$	12,635		$	23,454		$	39,895

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

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

In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which includes 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. Proceeds are subject to adjustments related to working capital. 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. Final settlement of working capital adjustments are currently being evaluated and are not expected to be material. For all periods presented in the accompanying Consolidated Statements of Income, the sale of CCC was classified as discontinued operations. There were no other active businesses classified as discontinued operations in the presented periods.

In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unit of Dominion Resources. 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 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. With respect to production from this area, CONSOL Energy has committed to be an anchor shipper on Dominion’s transmission system for 250,000 Dth/d with a primary term of 15 years. 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, our joint venture partner, acquired 50% of the acres and reimbursed CONSOL Energy for 50% of the associated costs.

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

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

In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play. CNX Gas Company paid $46,315 as an up-front bonus payment at closing. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. CNX Gas Company must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company foregoes the bonus. Our joint venture partner, Noble Energy, acquired a 50% undivided interest in the acreage and has reimbursed CNX Gas Company for 50% of the associated acquisition costs during the year ended December 31, 2013.

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

NOTE 3—OTHER INCOME:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Coal Contract Settlement	$	30,000	$	—	$	30,000	$	—
Rental Income	10,697		1,111		25,605		1,884
Equity in Earnings of Affiliates	14,062		11,869		21,512		16,666
Gathering Revenue	2,020		733		20,750		5,097
Royalty Income	4,476		4,931		9,755		8,757
Bailey Belt Settlement	4,275		—		4,275		—
Right of Way Issuance	513		25		2,413		1,708
Interest Income	676		4,477		1,300		11,401
Business Interruption Insurance	—		—		—		2,700
Other	3,258		5,374		9,421		8,694
Total Other Income	$	69,977	$	28,520	$	125,031	$	56,907

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

Components of net periodic costs (benefits) for the three and six months ended June 30 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,
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	4,483		$	5,581		$	8,791		$	11,287		$	2,331		$	4,849		$	4,663		$	9,698
Interest cost	8,993			8,909			18,144			17,752			12,097			29,619			24,194			59,237
Expected return on plan assets	(12,765		)	(12,711		)	(25,512		)	(24,855		)	—			—			—			—
Amortization of prior service credits	(346		)	(407		)	(692		)	(815		)	(2,196		)	(7,804		)	(4,392		)	(15,608		)
Recognized net actuarial loss	6,106			10,547			11,997			22,722			6,369			17,595			12,737			35,190
Settlement loss	20,707			5,087			20,707			32,202			—			—			—			—
Net periodic benefit cost	$	27,178		$	17,006		$	33,435		$	58,293		$	18,601		$	44,259		$	37,202		$	88,517

Expenses attributable to discontinued operations included in net periodic cost above were $2,517 and $5,380 for the three and six months ended June 30, 2013, respectively, for the Pension Plans; and were $25,504 and $50,898 for the three and six months ended June 30, 2013, respectively, for the Other Post-Employment Benefit Plan.

For the six months ended June 30, 2014, $16,387 was paid to the pension trust from operating cash flows. Currently, depending upon asset values and asset returns held in the trust, we expect to contribute an additional $9,000 to the pension trust in 2014. Net periodic benefit costs are allocated to Exploration and Production Costs, Direct Administrative and Selling Expenses and Coal Costs, Operating and Other Costs in the Consolidated Statements of Income.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made 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. Additional lump sum distributions during June 2014 resulted in another remeasurement at June 30, 2014. The May 31 and June 30, 2014 remeasurements used a discount rate of 4.26% at May 31 and June 30, 2014, 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. If CONSOL Energy incurs additional lump sum distributions from the plan in 2014, additional settlement charges will be recorded.

Lump sum payments also exceeded the settlement threshold during the three and six months ended June 30, 2013. Accordingly, CONSOL Energy recognized settlement expense of $5,087 and $32,202 for the three and six months ended June 30, 2013, respectively, 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 2013 settlement charges also resulted in a remeasurement of the pension plan at June 30 and March 31, 2013. The June 30, 2013 remeasurement resulted in a change to the discount rate to 4.84% from 4.12% at March 31, 2013. The June remeasurement reduced the pension liability by $48,957. The June settlement and corresponding remeasurement of the pension plan resulted in an increase of $33,414 in Other Comprehensive Income, net of $20,630 in deferred taxes. The March 31, 2013 remeasurement resulted in a change to the discount rate to 4.12% from 4.00% at December 31, 2012. The March remeasurement reduced the pension liability by $29,916. The March settlement and corresponding remeasurement of the pension plan resulted in an increase of $35,261 in Other Comprehensive Income, net of $21,770 in deferred taxes.

CONSOL Energy does not expect to contribute to the other post-employment benefits plan in 2014. We intend to pay benefit claims as they become due. For the six months ended June 30, 2014, $29,915 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 costs (benefits) for the three and six months ended June 30 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,
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	1,418		$	2,135		$	2,837		$	4,270		$	2,445		$	3,533		$	4,890		$	7,066
Interest cost	1,385			1,808			2,769			3,616			895			1,655			1,789			3,310
Amortization of actuarial gain	(1,549		)	(4,212		)	(3,098		)	(8,425		)	(96		)	(699		)	(191		)	(1,398		)
State administrative fees and insurance bond premiums	—			—			—			—			929			1,345			2,039			3,004
Legal and administrative costs	—			—			—			—			—			591			—			1,182
Net periodic cost (benefit)	$	1,254		$	(269	)	$	2,508		$	(539	)	$	4,173		$	6,425		$	8,527		$	13,164

Expenses (income) attributable to discontinued operations included in the net periodic cost (benefit) above were ($165) and ($330) for the three and six months ended June 30, 2013, respectively, for CWP; and were $2,318 and $4,853 for the three and six months ended June 30, 2013, respectively, for Workers' Compensation.

CONSOL Energy does not expect to contribute to the CWP plan in 2014. We intend to pay benefit claims as they become due. For the six months ended June 30, 2014, $6,062 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2014. We intend to pay benefit claims as they become due. For the six months ended June 30, 2014, $6,914 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 6—INCOME TAXES:

The effective tax rate on continuing operations for the six months ended June 30, 2014 and 2013 was 9.1% and 85.6%, respectively.

The effective rate for the six months ended June 30, 2014 differs from the U.S. federal statutory rate of 35% primarily due to a $20,480 income tax benefit for excess depletion, $8,820 discrete income tax benefit related to the completion of the Internal Revenue Service audit of tax years 2008 and 2009, and $7,395 discrete income tax benefit 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 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. The tax benefit of $8,351 related to increased percentage depletion deductions offset by $956 of tax expense related to changes in the Domestic Production Activities Deduction and various other estimates.

The rate for the six months ended June 30, 2013 differs from the U.S. federal statutory rate of 35% primarily due to a $25,471 income tax charge for excess depletion, $8,269 discrete income tax charge related to the gain on sale of the Potomac coal reserves and a $1,585 income tax benefit due to a refund claim related to prior year Commonwealth of Pennsylvania taxes.

The total amounts of uncertain tax positions at June 30, 2014 and December 31, 2013 were $2,540 and $22,770, respectively. If these uncertain tax positions were recognized, approximately $1,651 and $2,071, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the six months ended June 30, 2014 and 2013. The reduction in uncertain tax positions was due to the completion of the Internal Revenue Service audit of the 2008 and 2009 tax years.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of June 30, 2014 and December 31, 2013, the Company reported an accrued interest liability relating to uncertain tax positions of $1,302 and $6,200, respectively. The accrued interest liability includes $4,898 of interest income and $675 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the six months ended June 30, 2014 and 2013, respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of June 30, 2014 and December 31, 2013, 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 has issued its audit report related to the examination of CONSOL Energy’s 2008 and 2009 U.S. income tax returns during the six months ended June 30, 2014. As a result of these findings, CONSOL Energy paid federal income tax deficiencies of $4,464 and $1,001, respectively. The deficiencies were the result of changes in the timing of certain tax deductions. The changes in timing of these tax deductions increased the tax benefit of percentage depletion by $2,925 and $4,493 in tax years 2008 and 2009, respectively. The Company also recognized additional tax benefits of $1,402 primarily related to an increase in the Domestic Production Activities Deduction for the audited periods. Also, as a result of closing the IRS audit, CONSOL was required to file amended state income tax returns for the changes. In the quarter ended June 30, 2014, the Company filed the required amended returns and realized a discrete state income tax charge of $5,144 which was offset by a federal income tax benefit of $1,800.

NOTE 7—INVENTORIES:

Inventory components consist of the following:



	June 30, 2014		December 31, 2013
Coal	$	23,953	$	31,944
Merchandise for resale	39,251		38,263
Supplies	84,801		87,707
Total Inventories	$	148,005	$	157,914

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

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $19,418 and $18,836 at June 30, 2014 and December 31, 2013, respectively.

NOTE 8—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $125,000. The facility also allows for the issuance of letters of credit against the $125,000 capacity. At June 30, 2014, there were letters of credit outstanding against the facility of $61,930. CONSOL Energy management believes that these letters of credit will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

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

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

The cost of funds under this facility is based upon commercial paper rates or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $484 and $913 for the six months ended June 30, 2014 and 2013, respectively. These costs have been recorded as financing fees which are included in in the Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2015.

At June 30, 2014 and December 31, 2013, eligible accounts receivable totaled $85,900 and $115,000, respectively. There was $23,970 subordinated retained interest at June 30, 2014 and $48,945 subordinated retained interest at December 31, 2013. There were no borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of June 30, 2014 and no borrowings at December 31, 2013. The accounts receivable securitization program had no change in the six months ended June 30, 2014 and increased by $2,873 in the six months ended June 30, 2013. The increase is reflected in the Net Cash Used in Financing Activities in the Consolidated Statement of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

NOTE 9—PROPERTY, PLANT AND EQUIPMENT:



	June 30, 2014		December 31, 2013
Coal and other plant and equipment	$	3,711,184	$	3,681,051
Intangible drilling cost	2,228,806		1,937,336
Proven gas properties	1,683,052		1,670,404
Unproven gas properties	1,493,708		1,463,406
Coal properties and surface lands	1,407,518		1,409,408
Gas gathering equipment	1,074,265		1,058,008
Gas wells and related equipment	780,212		688,548
Airshafts	443,657		397,466
Mine development	416,296		354,607
Leased coal lands	388,033		388,020
Coal advance mining royalties	387,199		381,348
Other gas assets	124,903		126,239
Gas advance royalties	22,134		22,668
Total Property Plant and Equipment	14,160,967		13,578,509
Less: Accumulated DD&A	4,384,209		4,136,247
Total Net PP&E	$	9,776,758	$	9,442,262

Industry Participation Agreements

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

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 144 thousand 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, 2014, Hess’ remaining carry obligation is $175,582.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 696 thousand 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 $1,884,000 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. Due to the increase in average natural gas prices, the carry is in effect beginning March 1, 2014, and will remain effective until average natural gas prices are below $4.00/MMbtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of June 30, 2014, Noble Energy’s remaining carry obligation is $1,816,095.

NOTE 10—SHORT-TERM NOTES PAYABLE:

CONSOL Energy entered into a new Amended and Restated Credit Agreement dated June 18, 2014 for a $2,000,000 senior secured revolving credit facility which expires on June 18, 2019. The new senior revolving credit facility replaced CONSOL Energy's existing $1,000,000 senior secured revolving credit facility which had been entered into as of April 12, 2011 and amended and restated on December 5, 2013 and the existing $1,000,000 senior secured revolving credit facility of CNX Gas Corporation and its subsidiaries that had been entered into as of April 12, 2011. The new senior secured revolving credit facility resulted in the acceleration of previously deferred financing charges of $2,989 during the quarter ended June 30, 2014. 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 $2,000,000 of borrowings, which includes $750,000 in letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500,000 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 generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan 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 was 4.15 to 1.00 at June 30, 2014. The facility includes a minimum

current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio was 2.59 to 1.00 at June 30, 2014. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. 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, 2014, the $2,000,000 facility had no borrowings outstanding and $260,473 of letters of credit outstanding, leaving $1,739,527 of unused capacity. At December 31, 2013, the prior CONSOL Energy $1,000,000 facility had no borrowings outstanding and $206,988 of letters of credit outstanding, leaving $793,012 of unused capacity. At December 31, 2013, the prior CNX Gas Corporation $1,000,000 facility had no borrowings outstanding and $87,643 of letters of credit outstanding, leaving $912,357 of unused capacity.

NOTE 11—LONG-TERM DEBT:



	June 30, 2014		December 31, 2013
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	—	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		250,000
Senior notes due April 2022 at 5.875%, issued at par value	1,600,000		—
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.93% weighted average interest rate for June 30, 2014 and December 31, 2013)	11,182		11,182
Other long-term notes maturing at various dates through 2031 (total value of $5,236 and $5,923 less unamortized discount of $835 and $1,050 at June 30, 2014 and December 31, 2013, respectively).	4,401		4,873
	3,218,448		3,118,920
Less amounts due in one year *	3,535		2,957
Long-Term Debt	$	3,214,913	$	3,115,963

* Excludes current portion of Capital Lease Obligations of $8,592 and $8,498 at June 30, 2014 and December 31, 2013, respectively.

Accrued interest related to Long-Term Debt of $52,859 and $63,272 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 30, 2014 and December 31, 2013, respectively.

On April 16, 2014, CONSOL Energy closed on the private placement of $1,600,000 of 5.875% senior notes due 2022 (the "Notes"). The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy used substantially all of the net proceeds of the sale of the Notes to purchase the 8.00% senior notes due in 2017.

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 $390,096.

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

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos, and since many of the pending claims are asserted against dozens of defendants in any given action, it has been difficult for Fairmont to determine how many of the pending cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on nearly 20 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets. Past payments by Fairmont with respect to asbestos cases have not been material.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company, et. al. The lawsuit alleges that the putative class consists of forced-pooled unleased gas owners whose gas ownership was declared to be in conflict with rights of others even where the Virginia Supreme Court and General Assembly have purportedly decided that coalbed methane (CBM) belongs to the owner of the gas estate; that the Virginia Gas and Oil Act of 1990 unconstitutionally provides only a 1/8 net proceeds royalty to CBM owners for gas produced under the forced-pooled orders; and, that CNX Gas Company relied upon control of only the coal estate in force pooling the CBM notwithstanding decisions by the Virginia Supreme Court. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The lawsuit also alleges CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. In ruling on our Motion to Dismiss, the District Judge decided that the deemed lease provision of the Gas and Oil Act is constitutional, as is the 1/8 royalty. An amended complaint was filed, which added additional allegations that include gas hedging receipts should have been used as the basis for royalty payments, severance tax should not be allowed as a post-production deduction from royalties, and damages incurred because gas was produced prior to the entry of pooling orders. A motion to dismiss the Amended Complaint was filed and denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. On September 30, 2013, the District Judge entered an Order overruling CNX Gas Company’s Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CONSOL Energy believes this case cannot properly proceed as a class action and filed a Petition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a ruling on the Petition but assigning the case to a merits panel. The appeal was fully briefed, and oral argument was held before a three-judge panel of the Fourth Circuit on May 13, 2014. Plaintiffs filed Motions for Summary Judgment on the issue of ownership of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge heard argument on the summary judgment motions on January 6, 2014, but has not ruled on the Motions. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: A putative class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al. The lawsuit alleges that the plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit alleges that the Virginia Supreme Court and General Assembly have decided that the plaintiffs own the gas and are entitled to royalties held in escrow by the Commonwealth of Virginia or CNX Gas Company. The lawsuit also alleges CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breach of fiduciary duties; and unjust enrichment. The District Judge granted, in part, CNX Gas Company’s Motion to Dismiss. An Amended Complaint was filed which added an additional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and was denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. On September 30, 2013, the District Judge entered an Order overruling CNX Gas Company’s Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed a Petition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a ruling on the Petition but assigning the case to a merits panel. The appeal was fully briefed, and a three-judge panel of the Fourth

Circuit heard oral argument on May 13, 2014. Plaintiffs have filed Motions for Summary Judgment on the issue of ownership of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge heard argument on the summary judgment motions on January 6, 2014, but has not ruled on the Motions. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

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

Ratliff Litigation: On January 30, 2013, the Company was served with a complaint filed on behalf of four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, as well as CONSOL Energy itself in the United States District Court for the Western District of Virginia. The complaint seeks damages and injunctive relief in connection with the deposit of water from mining activities at the Buchanan Mine into nearby void spaces at some of the mines of ICCC, voids ostensibly underlying their property. The suit alleges damage to coal and coalbed methane and seeks recovery in tort, contract and assumpsit (quasi-contract). The suit seeks damages of approximately $50,000 plus punitive damages. The defendants have asserted Virginia's Mine Void Statute as a defense to plaintiffs’ claims and the plaintiffs have challenged the constitutionality of that statute. On March 18, 2014, the District Court concluded, in ruling on Defendants’ Motion to Dismiss, it could not resolve either the constitutionality or the applicability of the Mine Void Statute on the current record. Discovery is ongoing. CONSOL Energy intends to vigorously defend the suit.

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 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 Court rejected each of those claims, essentially holding that if CNX Gas Company went out of the coal seam, it had no intention to do so and, in any event, the plaintiff could not prove any damages as a result. 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. On March 28, 2014, Plaintiffs filed Notices of Appeal with the Pennsylvania Superior Court on all issues decided in CONSOL Energy’s favor.

Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources Inc., and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion Resources' sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently been permitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A motion to dismiss will be filed. Although initial mediation efforts were unsuccessful, another mediation session was held on May 27, 2014, and the parties continue to discuss settlement. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.

At June 30, 2014, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	151,311	$	117,542	$	33,769	$	—	$	—
Environmental	39,363		39,363		—		—		—
Other	131,802		58,979		72,823		—		—
Total Letters of Credit	322,476		215,884		106,592		—		—
Surety Bonds:
Employee-Related	204,893		194,893		10,000		—		—
Environmental	678,943		673,076		5,867		—		—
Other	26,887		26,840		46		—		1
Total Surety Bonds	910,723		894,809		15,913		—		1
Guarantees:
Coal	233,260		150,300		82,960		—		—
Other	67,717		35,611		10,470		14,462		7,174
Total Guarantees	300,977		185,911		93,430		14,462		7,174
Total Commitments	$	1,534,176	$	1,296,604	$	215,935	$	14,462	$	7,175

Included in the above table are commitments and guarantees entered into in conjunction with the sale of CCC 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. 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, 2014, the fair value of these guarantees was $3,000 and was included in Other Accrued Liabilities on the Consolidated Balance Sheets. The fair value of certain 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 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, 2014, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	172,295
1 - 3 years	381,321
3 - 5 years	355,532
More than 5 years	763,883
Total Purchase Obligations	$	1,673,031

Costs related to these purchase obligations include:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Major Equipment Purchases	$	11,474	$	5,654	$	90,161	$	8,747
Firm Transportation and Processing Expense	25,424		21,689		49,363		42,821
Gas Drilling Obligations	30,226		25,904		52,450		54,768
Total Costs Related to Purchase Obligations	$	67,124	$	53,247	$	191,974	$	106,336

NOTE 13—DERIVATIVE INSTRUMENTS:

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

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

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

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

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

CONSOL Energy has entered into swap and option contracts for natural gas to manage the price risk associated with the forecasted natural gas sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of June 30, 2014, the total notional amount of the Company’s outstanding derivative instruments was 241.4 billion cubic feet. These derivative instruments are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be

shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $319 of unrealized loss is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Natural Gas, NGL's and Oil Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at June 30, 2014 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $41,362 and a liability of $32,601. The total asset is comprised of $27,593 and $13,769 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $28,458 and $4,143 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The gross fair value at December 31, 2013 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $83,661 and a liability of $18,212. The total asset is comprised of $59,605 and $24,056 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $12,327 and $5,885 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

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



	For the Three Months Ended June 30,
	2014			2013
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	11,841		$	35,453
(Loss)/Gain recognized in Accumulated OCI	(12,218		)	45,749
Less: (Loss)/Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales	(6,951		)	9,528
Ending Balance – Accumulated OCI	$	6,574		$	71,674
Gain/(Loss) recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness	$	508		$	(3,753	)



	For the Six Months Ended June 30,
	2014			2013
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	42,493		$	76,761
(Loss)/Gain recognized in Accumulated OCI	(59,183		)	27,154
Less: (Loss)/Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales	(23,264		)	32,241
Ending Balance – Accumulated OCI	$	6,574		$	71,674
Gain/(Loss) recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness	$	863		$	(2,712	)

There were no amounts excluded from the assessment of hedge effectiveness in 2014 or 2013.

NOTE 14—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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



	Fair Value Measurements at June 30, 2014						Fair Value Measurements at December 31, 2013
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	8,761	$	—	$	—	$	65,449	$	—
Murray Energy Guarantees	$	—	$	—	$	3,000	$	—	$	—	$	3,000

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

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

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, 2014						December 31, 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	147,393		$	147,393		$	327,420		$	327,420
Long-Term Debt	$	(3,218,448	)	$	(3,430,827	)	$	(3,118,920	)	$	(3,299,875	)

NOTE 15—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Exploration and Production (E&P) and Coal. The principal activity of the E&P division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division includes four reportable segments. These reportable segments are Marcellus, Coalbed Methane, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as various other activities assigned to the E&P division but not allocated to each individual well type. The principal activities of the Coal division are mining, preparation and marketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three months ended June 30, 2014, the Thermal aggregated segment includes the following mines: Bailey Complex, Enlow Fork, Harvey Mine and Miller Creek Complex. For the three months ended June 30, 2014, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the three months ended June 30, 2014, the High Volatile Metallurgical aggregated segment includes: Bailey Complex, Enlow Fork, and Harvey Mine coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to each individual mine. CONSOL Energy’s All Other segment includes industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the E&P or coal segment. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (E&P, coal, and other) and are not allocated between each individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

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



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P		Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	104,584	$	80,681	$	26,556		$	17,922		$	229,743	$	446,416	$	66,771	$	20,483	$	2,628		$	536,298	$	70,087	$	—		$	836,128		(A)
Sales—purchased gas	—		—		—			1,404			1,404		—		—		—		—			—		—		—			1,404
Sales—gas royalty interests	—		—		—			18,335			18,335		—		—		—		—			—		—		—			18,335
Freight—outside	—		—		—			—			—		—		—		—		10,109			10,109		—		—			10,109
Intersegment transfers	—		—		—			555			555		—		—		—		—			—		20,034		(20,589		)	—
Total Sales and Freight	$	104,584	$	80,681	$	26,556		$	38,216		$	250,037	$	446,416	$	66,771	$	20,483	$	12,737		$	546,407	$	90,121	$	(20,589	)	$	865,976
Earnings (Loss) Before Income Taxes	$	34,764	$	17,949	$	(5,096	)	$	(24,242	)	$	23,375	$	111,906	$	9,292	$	7,571	$	(9,167	)	$	119,602	$	1,755	$	(168,453	)	$	(23,721	)	(B)
Segment assets											$	6,797,166										$	4,110,704	$	297,044	$	361,733		$	11,566,647		(C)
Depreciation, depletion and amortization											$	71,499										$	65,086	$	1,314	$	—		$	137,899
Capital expenditures											$	304,486										$	63,269	$	531	$	—		$	368,286

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

(B) Includes equity in earnings of unconsolidated affiliates of $6,996, $6,933 and $133 for E&P, Coal and All Other, respectively.

(C) Includes investments in unconsolidated equity affiliates of $259,870, $23,128 and $69,189 for E&P, Coal and All Other, respectively.

Industry segment results for the three months ended June 30, 2013 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P			Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	46,577	$	87,799	$	33,745		$	3,115		$	171,236		$	335,926	$	111,006	$	53,189	$	4,939		$	505,060	$	65,218	$	—		$	741,514	(D)
Sales—purchased gas	—		—		—			1,406			1,406			—		—		—		—			—		—		—			1,406
Sales—gas royalty interests	—		—		—			17,028			17,028			—		—		—		—			—		—		—			17,028
Freight—outside	—		—		—			—			—			—		—		—		9,660			9,660		—		—			9,660
Intersegment transfers	—		—		—			926			926			—		—		—		—			—		32,427		(33,353		)	—
Total Sales and Freight	$	46,577	$	87,799	$	33,745		$	22,475		$	190,596		$	335,926	$	111,006	$	53,189	$	14,599		$	514,720	$	97,645	$	(33,353	)	$	769,608
Earnings (Loss) Before Income Taxes	$	11,680	$	22,125	$	(5,591	)	$	(32,821	)	$	(4,607	)	$	87,915	$	30,818	$	16,768	$	(29,716	)	$	105,785	$	4,887	$	(67,938	)	$	38,127	(E)
Segment assets											$	6,170,531											$	4,211,872	$	363,819	$	2,006,706		$	12,752,928	(F)
Depreciation, depletion and amortization											$	52,846											$	55,247	$	1,436	$	—		$	109,529
Capital expenditures											$	188,464											$	163,097	$	6,074	$	—		$	357,635


(D)	Included in the Coal segment are sales of $127,734 and $84,602 to Xcoal Energy & Resources and Duke Energy, which comprises over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $1,031, $10,762 and $76 for E&P, Coal and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $170,589, $22,119 and $63,389 for E&P, Coal and All Other, respectively.

Industry segment results for the six months ended June 30, 2014 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P		Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	229,541	$	176,752	$	58,901		$	30,847		$	496,041	$	863,385	$	151,312	$	49,415	$	6,867		$	1,070,979	$	139,374	$	—		$	1,706,394	(G)
Sales—purchased gas	—		—		—			4,978			4,978		—		—		—		—			—		—		—			4,978
Sales—gas royalty interests	—		—		—			44,980			44,980		—		—		—		—			—		—		—			44,980
Freight—outside	—		—		—			—			—		—		—		—		20,054			20,054		—		—			20,054
Intersegment transfers	—		—		—			1,452			1,452		—		—		—		—			—		39,346		(40,798		)	—
Total Sales and Freight	$	229,541	$	176,752	$	58,901		$	82,257		$	547,451	$	863,385	$	151,312	$	49,415	$	26,921		$	1,091,033	$	178,720	$	(40,798	)	$	1,776,406
Earnings (Loss) Before Income Taxes	$	93,869	$	51,568	$	(6,853	)	$	(37,665	)	$	100,919	$	260,473	$	20,722	$	16,675	$	(71,104	)	$	226,766	$	3,252	$	(224,478	)	$	106,459	(H)
Segment assets											$	6,797,166										$	4,110,704	$	297,044	$	361,733		$	11,566,647	(I)
Depreciation, depletion and amortization											$	143,228										$	121,149	$	2,638	$	—		$	267,015
Capital expenditures											$	570,456										$	247,700	$	1,139	$	—		$	819,295


(G)	Included in the Coal segment are sales of $189,921 and $188,491 to Duke Energy and Xcoal Energy & Resources, respectively, which comprises over 10% of sales.


(H)	Includes equity in earnings of unconsolidated affiliates of $12,810, $9,793 and $(1,091) for E&P, Coal and All Other, respectively.

(I) Includes investments in unconsolidated equity affiliates of $259,870, $23,128 and $69,189 for E&P, Coal and All Other, respectively.

Industry segment results for the six months ended June 30, 2013 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P			Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	94,988	$	171,439	$	66,181		$	6,470		$	339,078		$	681,866	$	257,834	$	102,667	$	10,602		$	1,052,969	$	133,902	$	—		$	1,525,949	(J)
Sales—purchased gas	—		—		—			2,764			2,764			—		—		—		—			—		—		—			2,764
Sales—gas royalty interests	—		—		—			31,232			31,232			—		—		—		—			—		—		—			31,232
Freight—outside	—		—		—			—			—			—		—		—		21,913			21,913		—		—			21,913
Intersegment transfers	—		—		—			1,762			1,762			—		—		—		—			—		67,905		(69,667		)	—
Total Sales and Freight	$	94,988	$	171,439	$	66,181		$	42,228		$	374,836		$	681,866	$	257,834	$	102,667	$	32,515		$	1,074,882	$	201,807	$	(69,667	)	$	1,581,858
Earnings (Loss) Before Income Taxes	$	25,448	$	43,305	$	(9,629	)	$	(64,374	)	$	(5,250	)	$	181,373	$	85,535	$	27,506	$	(88,972	)	$	205,442	$	7,461	$	(174,142	)	$	33,511	(K)
Segment assets											$	6,170,531											$	4,211,872	$	363,819	$	2,006,706		$	12,752,928	(L)
Depreciation, depletion and amortization											$	105,834											$	112,437	$	2,836	$	—		$	221,107
Capital expenditures											$	395,593											$	304,348	$	7,511	$	—		$	707,452


(J)	Included in the Coal segment are sales of $285,338 and $160,932 to Xcoal Energy & Resources and Duke Energy, respectively, which comprises over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $4,212, $12,294 and $160 for E&P, Coal and All Other, respectively.

(L) Includes investments in unconsolidated equity affiliates of $170,589, $22,119 and $63,389 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,
	2014			2013			2014			2013
Segment Earnings Before Income Taxes for total reportable business segments	$	142,977		$	101,178		$	327,685		$	200,192
Segment Earnings Before Income Taxes for all other businesses	1,755			4,887			3,252			7,461
Interest expense, net and other non-operating activity (M)	(144,013		)	(56,403		)	(197,956		)	(109,063		)
Other Corporate Items (M)	(24,440		)	(11,535		)	(26,522		)	(65,079		)
Earnings Before Income Taxes	$	(23,721	)	$	38,127		$	106,459		$	33,511



Total Assets:	June 30,
Total Assets:	2014		2013
Segment assets for total reportable business segments	$	10,907,870	$	10,382,403
Segment assets for all other businesses	297,044		363,819
Items excluded from segment assets:
Cash and other investments (M)	136,266		45,885
Recoverable income taxes	47,060		1,930
Deferred tax assets	137,716		84,402
Bond issuance costs	40,691		38,102
Discontinued Operations	—		1,836,387
Total Consolidated Assets	$	11,566,647	$	12,752,928

_________________________

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,250,000, 8.250% per annum senior notes due April 1, 2020, the $250,000, 6.375% per annum senior notes due March 1, 2021, and the $1,600,000, 5.875% per annum senior notes due April 1, 2022 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the Three Months Ended June 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
Gas Royalty Interests and Purchased Gas Sales	—			19,739		—			—		—			19,739
Freight-Outside Coal	—			—		10,109			—		—			10,109
Miscellaneous Other Income	91,968			9,673		57,623			2,740		(92,027		)	69,977
Gain (Loss) on Sale of Assets	—			2,920		(1,505		)	2		—			1,417
Total Revenue and Other Income	91,968			262,631		612,552			62,802		(92,583		)	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	—			21,012		—			—		—			21,012
General and Administrative	—			15,517		—			—		—			15,517
Total Exploration and Production Costs	—			237,142		—			—		—			237,142
Coal Costs
Operating and Other Costs	5,571			—		342,526			—		(556		)	347,541
Royalties and Production Taxes	—			—		27,603			—					27,603
Direct Administrative and Selling	—			—		11,816			—		—			11,816
Depreciation, Depletion and Amortization	157			—		64,929			—		—			65,086
Freight Expense	—			—		10,109			—		—			10,109
General and Administrative Costs	—			—		10,450			—		—			10,450
Other Corporate Expenses	12,035			—		—			—		—			12,035
Total Coal Costs	17,763			—		467,433			—		(556		)	484,640
Other Costs
Miscellaneous Operating Expense	32,986			—		7,593			59,644		(1,144		)	99,079
General and Administrative Costs	—			—		207			221		—			428
Depreciation, Depletion and Amortization	7			—		817			490		—			1,314
Loss on Debt Extinguishment	74,277			—		—			—		—			74,277
Interest Expense	61,389			2,155		1,949			40		(1,322		)	64,211
Total Other Costs	168,659			2,155		10,566			60,395		(2,466		)	239,309
Total Costs And Expenses	186,422			239,297		477,999			60,395		(3,022		)	961,091
(Loss) Earnings Before Income Tax	(94,454		)	23,334		134,553			2,407		(89,561		)	(23,721		)
Income Taxes	(69,519		)	7,833		61,991			909		—			1,214
(Loss) Income From Continuing Operations	(24,935		)	15,501		72,562			1,498		(89,561		)	(24,935		)
Income From Discontinued Operations, net	—			—		—			—		—			—
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(24,935	)	$	15,501	$	72,562		$	1,498	$	(89,561	)	$	(24,935	)

Balance Sheet at June 30, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	134,563		$	11,984	$	—		$	846	$	—		$	147,393
Accounts and Notes Receivable:
Trade	—			74,285		—			201,146		—			275,431
Notes Receivable	1,328			—		—			—		—			1,328
Other Receivables	43,968			300,672		41,831			4,013		—			390,484
Inventories	—			15,076		93,925			39,004		—			148,005
Deferred Income Taxes	127,367			10,349		—			—		—			137,716
Recoverable Income Taxes	40,402			6,658		—			—		—			47,060
Prepaid Expenses	27,524			31,406		17,641			1,867		—			78,438
Total Current Assets	375,152			450,430		153,397			246,876		—			1,225,855
Property, Plant and Equipment:
Property, Plant and Equipment	166,798			7,417,046		6,550,916			26,207		—			14,160,967
Less-Accumulated Depreciation, Depletion and Amortization	118,911			1,329,866		2,915,856			19,576		—			4,384,209
Total Property, Plant and Equipment-Net	47,887			6,087,180		3,635,060			6,631		—			9,776,758
Other Assets:
Investment in Affiliates	12,078,724			259,870		123,405			—		(12,109,812		)	352,187
Other	146,874			16,685		39,512			8,776		—			211,847
Total Other Assets	12,225,598			276,555		162,917			8,776		(12,109,812		)	564,034
Total Assets	$	12,648,637		$	6,814,165	$	3,951,374		$	262,283	$	(12,109,812	)	$	11,566,647
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	49,144		$	359,479	$	83,650		$	11,736	$	—		$	504,009
Accounts Payable (Recoverable)—Related Parties	4,406,801			114,744		(5,188,815		)	72,170		595,100			—
Current Portion Long-Term Debt	1,524			6,546		3,331			726		—			12,127
Short-Term Notes Payable	—			595,100		—			—		(595,100		)	—
Other Accrued Liabilities	103,400			120,000		322,966			8,110		—			554,476
Current Liabilities of Discontinued Operations	—			—		—			13,054		—			13,054
Total Current Liabilities	4,560,869			1,195,869		(4,778,868		)	105,796		—			1,083,666
Long-Term Debt:	3,104,101			40,331		113,082			1,867		—			3,259,381
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(198,720		)	490,648		—			—		—			291,928
Postretirement Benefits Other Than Pensions	—			—		959,034			—		—			959,034
Pneumoconiosis Benefits	—			—		111,519			—		—			111,519
Mine Closing	—			—		320,902			—		—			320,902
Gas Well Closing	—			120,508		59,589			—		—			180,097
Workers’ Compensation	—			—		73,065			341		—			73,406
Salary Retirement	58,962			—		—			—		—			58,962
Reclamation	—			—		35,779			—		—			35,779
Other	63,767			61,550		6,998			—		—			132,315
Total Deferred Credits and Other Liabilities	(75,991		)	672,706		1,566,886			341		—			2,163,942
Total CONSOL Energy Inc. Stockholders’ Equity	5,059,658			4,905,259		7,050,274			154,279		(12,109,812		)	5,059,658
Total Liabilities and Equity	$	12,648,637		$	6,814,165	$	3,951,374		$	262,283	$	(12,109,812	)	$	11,566,647

Income Statement for the Three Months Ended June 30, 2013 (unaudited):



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	172,139		$	—		$	—		$	(903	)	$	171,236
Coal Sales	—			—			505,060			—			—			505,060
Other Outside Sales	—			—			11,608			53,610			—			65,218
Gas Royalty Interests and Purchased Gas Sales	—			18,434			—			—			—			18,434
Freight-Outside Coal	—			—			9,660			—			—			9,660
Miscellaneous Other Income	198,207			6,087			(12,257		)	5,407			(168,924		)	28,520
Gain (Loss) on Sale of Assets	—			5,169			24,873			(3		)	—			30,039
Total Revenue and Other Income	198,207			201,829			538,944			59,014			(169,827		)	828,167
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			25,221			—			—			—			25,221
Transportation, Gathering and Compression	—			48,871			—			—			—			48,871
Production, Ad Valorem, and Other Fees	—			7,409			—			—			—			7,409
Direct Administrative and Selling	—			11,803			—			—			—			11,803
Depreciation, Depletion and Amortization	—			52,846			—			—			—			52,846
Exploration and Production Related Other Costs	—			10,406			—			—			—			10,406
Production Royalty Interests and Purchased Gas Costs	—			14,605			—			—			(10		)	14,595
Other Corporate Expenses	—			22,557			—			—			—			22,557
General and Administrative	—			10,472			—			—			—			10,472
Total Exploration and Production Costs	—			204,190			—			—			(10		)	204,180
Coal Costs
Operating and Other Costs	1,996			—			264,775			—			63,163			329,934
Royalties and Production Taxes	—			—			26,438			—			—			26,438
Direct Administrative and Selling	—			—			12,252			—			—			12,252
Depreciation, Depletion and Amortization	5,931			—			49,316			—			—			55,247
Freight Expense	—			—			9,660			—			—			9,660
General and Administrative Costs	—			—			10,038			—			—			10,038
Other Corporate Expenses	11,996			—			—			—			—			11,996
Total Coal Costs	19,923			—			372,479			—			63,163			455,565
Other Costs
Miscellaneous Operating Expense	22,533			—			5,006			54,685			(8,352		)	73,872
General and Administrative Costs	—			—			174			296			—			470
Depreciation, Depletion and Amortization	364			—			574			498			—			1,436
Loss on Extinguishment of Debt	—			—			—			—			—			—
Interest Expense	50,807			2,135			1,679			10			(114		)	54,517
Total Other Costs	73,704			2,135			7,433			55,489			(8,466		)	130,295
Total Costs And Expenses	93,627			206,325			379,912			55,489			54,687			790,040
Earnings (Loss) Before Income Tax	104,580			(4,496		)	159,032			3,525			(224,514		)	38,127
Income Taxes	117,106			(1,747		)	(81,749		)	(4,045		)	—			29,565
(Loss) Income From Continuing Operations	(12,526		)	(2,749		)	240,781			7,570			(224,514		)	8,562
Loss From Discontinued Operations, net	—			—			—			(21,375		)	—			(21,375		)
Net (Loss) Income	(12,526		)	(2,749		)	240,781			(13,805		)	(224,514		)	(12,813		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(287		)	—			—			—			(287		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(12,526	)	$	(2,462	)	$	240,781		$	(13,805	)	$	(224,514	)	$	(12,526	)

Balance Sheet at December 31, 2013:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	320,473		$	6,238		$	—		$	709	$	—		$	327,420
Accounts and Notes Receivable:
Trade	—			71,911			—			260,663		—			332,574
Notes Receivable	1,238			—			24,623			—		—			25,861
Other Receivables	17,657			207,128			14,969			4,219		—			243,973
Inventories	—			15,185			99,320			43,409		—			157,914
Deferred Income Taxes	219,566			(8,263		)	—			—		—			211,303
Recoverable Income Taxes	(16,262		)	26,967			—			—		—			10,705
Prepaid Expenses	43,698			65,701			24,915			1,528		—			135,842
Total Current Assets	586,370			384,867			163,827			310,528		—			1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	173,719			6,919,972			6,459,014			25,804		—			13,578,509
Less-Accumulated Depreciation, Depletion and Amortization	122,022			1,188,464			2,806,775			18,986		—			4,136,247
Total Property, Plant and Equipment-Net	51,697			5,731,508			3,652,239			6,818		—			9,442,262
Other Assets:
Investment in Affiliates	11,965,054			206,060			70,222			—		(11,949,661		)	291,675
Notes Receivable	125			—			—			—		—			125
Other	145,401			30,728			28,831			9,053		—			214,013
Total Other Assets	12,110,580			236,788			99,053			9,053		(11,949,661		)	505,813
Total Assets	$	12,748,647		$	6,353,163		$	3,915,119		$	326,399	$	(11,949,661	)	$	11,393,667
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	91,553		$	324,226		$	89,201		$	9,600	$	—		$	514,580
Accounts Payable (Recoverable)-Related Parties	4,629,131			23,287			(5,121,727		)	136,822		332,487			—
Current Portion of Long-Term Debt	1,029			6,258			3,372			796		—			11,455
Short-Term Notes Payable	—			332,487			—			—		(332,487		)	—
Other Accrued Liabilities	144,612			89,080			322,606			9,399		—			565,697
Current Liabilities of Discontinued Operations	—			—			—			28,239		—			28,239
Total Current Liabilities	4,866,325			775,338			(4,706,548		)	184,856		—			1,119,971
Long-Term Debt:	3,005,458			42,852			113,474			1,775		—			3,163,559
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(232,904		)	475,547			—			—		—			242,643
Postretirement Benefits Other Than Pensions	—			—			961,127			—		—			961,127
Pneumoconiosis Benefits	—			—			111,971			—		—			111,971
Mine Closing	—			—			320,723			—		—			320,723
Gas Well Closing	—			119,429			56,174			—		—			175,603
Workers’ Compensation	—			—			71,136			332		—			71,468
Salary Retirement	48,252			—			—			—		—			48,252
Reclamation	—			—			40,706			—		—			40,706
Other	55,227			61,190			14,938			—		—			131,355
Total Deferred Credits and Other Liabilities	(129,425		)	656,166			1,576,775			332		—			2,103,848
Total CONSOL Energy Inc. Stockholders’ Equity	5,006,289			4,878,807			6,931,418			139,436		(11,949,661		)	5,006,289
Total Liabilities and Equity	$	12,748,647		$	6,353,163		$	3,915,119		$	326,399	$	(11,949,661	)	$	11,393,667

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
Gas Royalty Interests and Purchased Gas Sales	—			49,958		—			—			—			49,958
Freight-Outside Coal	—			—		20,054			—			—			20,054
Miscellaneous Other Income	261,535			37,830		82,436			5,042			(261,812		)	125,031
Gain (Loss) on Sale of Assets	—			6,072		(991		)	5			—			5,086
Total Revenue and Other Income	261,535			591,353		1,192,988			123,911			(263,264		)	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	—			47,176		—			—			—			47,176
General and Administrative	—			32,881		—			—			—			32,881
Total Exploration and Production Costs	—			486,470		—			—			(12		)	486,458
Coal Costs
Operating and Other Costs	16,602			—		659,240			—			(1,452		)	674,390
Royalties and Production Taxes	—			—		54,091			—			—			54,091
Direct Administrative and Selling	—			—		23,110			—			—			23,110
Depreciation, Depletion and Amortization	313			—		120,836			—			—			121,149
Freight Expense	—			—		20,054			—			—			20,054
General and Administrative Costs	—			—		22,963			—			—			22,963
Other Corporate Expenses	31,330			—		—			—			—			31,330
Total Coal Costs	48,245			—		900,294			—			(1,452		)	947,087
Other Costs
Miscellaneous Operating Expense	40,222			—		15,300			118,106			—			173,628
General and Administrative Costs	—			—		403			431			—			834
Depreciation, Depletion and Amortization	13			—		1,662			963			—			2,638
Loss on Debt Extinguishment	74,277			—		—			—			—			74,277
Interest Expense	109,822			3,964		3,533			103			(2,280		)	115,142
Total Other Costs	224,334			3,964		20,898			119,603			(2,280		)	366,519
Total Costs And Expenses	272,579			490,434		921,192			119,603			(3,744		)	1,800,064
Earnings (Loss) Before Income Tax	(11,044		)	100,919		271,796			4,308			(259,520		)	106,459
Income Taxes	(102,113		)	38,547		71,640			1,629			—			9,703
Income (Loss) From Continuing Operations	91,069			62,372		200,156			2,679			(259,520		)	96,756
Loss From Discontinued Operations, net	—			—		—			(5,687		)	—			(5,687		)
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	91,069		$	62,372	$	200,156		$	(3,008	)	$	(259,520	)	$	91,069

Income Statement for the Six Months Ended June 30, 2013 (unaudited)



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	340,818		$	—		$	—		$	(1,740	)	$	339,078
Coal Sales	—			—			1,052,969			—			—			1,052,969
Other Outside Sales	—			—			26,239			107,663			—			133,902
Gas Royalty Interests and Purchased Gas Sales	—			33,996			—			—			—			33,996
Freight-Outside Coal	—			—			21,913			—			—			21,913
Miscellaneous Other Income	276,183			18,856			27,274			10,777			(276,183		)	56,907
Gain (Loss) on Sale of Assets	—			5,625			26,720			—			—			32,345
Total Revenue and Other Income	276,183			399,295			1,155,115			118,440			(277,923		)	1,671,110
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			47,235			—			—			—			47,235
Transportation, Gathering and Compression	—			97,303			—			—			—			97,303
Production, Ad Valorem, and Other Fees	—			11,978			—			—			—			11,978
Direct Administrative and Selling	—			22,889			—			—			—			22,889
Depreciation, Depletion and Amortization	—			105,834			—			—			—			105,834
Exploration and Production Related Other Costs	—			20,895			—			—			—			20,895
Production Royalty Interests and Purchased Gas Costs	—			27,381			—			—			(21		)	27,360
Other Corporate Expenses	—			47,950			—			—			—			47,950
General and Administrative	—			19,062			—			—			—			19,062
Total Exploration and Production Costs	—			400,527			—			—			(21		)	400,506
Coal Costs
Operating and Other Costs	3,129			—			599,878			—			61,942			664,949
Royalties and Production Taxes	—			—			54,877			—			—			54,877
Direct Administrative and Selling	—			—			23,136			—			—			23,136
Depreciation, Depletion and Amortization	6,077			—			106,360			—			—			112,437
Freight Expense	—			—			21,913			—			—			21,913
General and Administrative Costs	—			—			19,339			—			—			19,339
Other Corporate Expenses	31,911			—			—			—			—			31,911
Total Coal Costs	41,117			—			825,503			—			61,942			928,562
Other Costs
Miscellaneous Operating Expense	68,139			—			30,006			109,768			(11,005		)	196,908
General and Administrative Costs	—			—			333			560			—			893
Depreciation, Depletion and Amortization	370			—			1,484			982			—			2,836
Loss on Extinguishment of Debt	—			—			—			—			—			—
Interest Expense	100,976			3,797			3,321			21			(221		)	107,894
Total Other Costs	169,485			3,797			35,144			111,331			(11,226		)	308,531
Total Costs And Expenses	210,602			404,324			860,647			111,331			50,695			1,637,599
Earnings (Loss) Before Income Tax	65,581			(5,029		)	294,468			7,109			(328,618		)	33,511
Income Taxes	79,671			(1,955		)	(46,354		)	(2,689		)	—			28,673
(Loss) Income From Continuing Operations	(14,090		)	(3,074		)	340,822			9,798			(328,618		)	4,838
Loss From Discontinued Operations, net	—			—			—			(19,472		)	—			(19,472		)
Net (Loss) Income	(14,090		)	(3,074		)	340,822			(9,674		)	(328,618		)	(14,634		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(544		)	—			—			—			(544		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(14,090	)	$	(2,530	)	$	340,822		$	(9,674	)	$	(328,618	)	$	(14,090	)

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		)
Net Cash Used in Discontinued Investing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Investing Activities	$	(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	(1,583,965		)	—			—			—			—			(1,583,965		)
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	—			(2,956		)	2,956			—			—			—
Net Cash (Used in) Provided by Continuing Operations	(11,280		)	259,657			2,704			(422		)	(262,613		)	(11,954		)
Net Cash Used in Discontinued Financing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Financing Activities	$	(11,280	)	$	259,657		$	2,704		$	(422	)	$	(262,613	)	$	(11,954	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	168,661		$	263,284		$	(4,205	)	$	(173,594	)	$	51,800		$	305,946
Net Cash Provided by Discontinued Operating Activities	—			—			—			87,444			—			87,444
Net Cash Provided by (Used in) Operating Activities	$	168,661		$	263,284		$	(4,205	)	$	(86,150	)	$	51,800		$	393,390
Cash Flows from Investing Activities:
Capital Expenditures	$	(7,511	)	$	(395,593	)	$	(304,348	)	$	—		$	—		$	(707,452	)
Change in Restricted Cash	—			—			68,673			—			—			68,673
Proceeds From Sales of Assets	(133,175		)	5,644			235,144			13			—			107,626
(Investments in), net of Distributions from, Equity Affiliates	—			(22,501		)	5,901			—			—			(16,600		)
Net Cash (Used in) Provided by Continuing Operations	(140,686		)	(412,450		)	5,370			13			—			(547,753		)
Net Cash Provided by Discontinued Investing Activities	—			—			—			82,627			—			82,627
Net Cash (Used in) Provided by Investing Activities	$	(140,686	)	$	(412,450	)	$	5,370		$	82,640		$	—		$	(465,126	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	224,800		$	—		$	—		$	(51,800	)	$	173,000
Payments on Miscellaneous Borrowings	(26,280		)	—			(3,357		)	(327		)	—			(29,964		)
Proceeds from Securitization Facility	—			—			—			2,873			—			2,873
Tax Benefit from Stock-Based Compensation	2,185			—			—			—			—			2,185
Dividends Paid	21,399			(50,000		)	—			—			—			(28,601		)
Proceeds from Issuance of Common Stock	2,497			—			—			—			—			2,497
Capital Lease Payments	—			(2,135		)	2,135			—			—			—
Net Cash (Used in) Provided by Continuing Operations	(199		)	172,665			(1,222		)	2,546			(51,800		)	121,990
Net Cash Used in Discontinued Financing Activities	—			—			—			(198		)	—			(198		)
Net Cash (Used in) Provided by Financing Activities	$	(199	)	$	172,665		$	(1,222	)	$	2,348		$	(51,800	)	$	121,792

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		$	72,562		$	1,498	$	(89,561	)	$	(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 Attributable to CONSOL Energy Inc. Shareholders	$	(34,000	)	$	10,234		$	68,764		$	1,498	$	(80,496	)	$	(34,000	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Net (Loss) Income	$	(12,526	)	$	(2,749	)	$	240,781	$	(13,805	)	$	(224,514	)	$	(12,813	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	42,904			—			42,904		—			(42,904		)	42,904
Net Increase (Decrease) in the Value of Cash Flow Hedge	45,749			45,749			—		—			(45,749		)	45,749
Reclassification of Cash Flow Hedge from OCI to Earnings	(9,528		)	(9,528		)	—		—			9,528			(9,528		)
Other Comprehensive Income (Loss):	79,125			36,221			42,904		—			(79,125		)	79,125
Comprehensive Income (Loss)	66,599			33,472			283,685		(13,805		)	(303,639		)	66,312
Less: Comprehensive (Loss) Attributable to Noncontrolling Interest	—			(287		)	—		—			—			(287		)
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	66,599		$	33,759		$	283,685	$	(13,805	)	$	(303,639	)	$	66,599

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		$	200,156	$	(3,008	)	$	(259,520	)	$	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) Attributable to CONSOL Energy Inc. Shareholders	$	56,471		$	26,453		$	201,477	$	(3,008	)	$	(224,922	)	$	56,471

Statement of Comprehensive Income for the Six Months Ended June 30, 2013 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Net (Loss) Income	$	(14,090	)	$	(3,074	)	$	340,822	$	(9,674	)	$	(328,618	)	$	(14,634	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	88,661			—			88,661		—			(88,661		)	88,661
Net Increase (Decrease) in the Value of Cash Flow Hedge	27,154			27,154			—		—			(27,154		)	27,154
Reclassification of Cash Flow Hedge from OCI to Earnings	(32,241		)	(32,241		)	—		—			32,241			(32,241		)
Other Comprehensive Income (Loss):	83,574			(5,087		)	88,661		—			(83,574		)	83,574
Comprehensive Income (Loss)	69,484			(8,161		)	429,483		(9,674		)	(412,192		)	68,940
Less: Comprehensive (Loss) Attributable to Noncontrolling Interest	—			(544		)	—		—			—			(544		)
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	69,484		$	(7,617	)	$	429,483	$	(9,674	)	$	(412,192	)	$	69,484

NOTE 17—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the six months ended June 30, 2014, CONE Gathering LLC (CONE), a 50% owned affiliate, provided CNX Gas Company LLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $14,382 and $26,207 for the three and six months ended June 30, 2014, respectively, and were $6,301 and $14,781 for the three and six months ended June 30, 2013, respectively, which were included in Exploration and Production Costs - Transportation, Gathering and Compression on the Consolidated Statements of Income.

As of June 30, 2014 and December 31, 2013, CONSOL Energy had a net payable of $4,267 and $5,448, respectively, due to CONE which was comprised of the following items:



	June 30,			December 31,
	2014			2013			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(478	)	$	(2,168	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(83		)	(265		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	(283		)	—			Accounts Receivable–Other
CONE Gathering Fee Payable	5,111			7,881			Accounts Payable
Net Payable due to CONE	$	4,267		$	5,448

NOTE 18—RECENT ACCOUNTING PRONOUNCEMENTS:

In June 2014, the Financial Accounting Standards Board (FASB) issued Update 2014-12 - Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. The objective of the amendments in this update is to resolve the diverse accounting treatment of share-based payment awards. The amendments in this update apply to all reporting entities that grant their employees share-based payments in which the terms of the award provide that a performance target that affects vesting could be achieved after the requisite service period. The amendments require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in either (i) the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered or (ii) if the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period will reflect the number of awards that are expected to vest and will be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in this update are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in this update either (a) prospectively to all awards granted or modified after the effective date or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We are currently still evaluating the impact this guidance may have on our operations.

In May 2014, the Financial Accounting Standards Board issued Update 2014-09 - Revenue from Contracts with Customers (Topic 606). The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for accounting principles generally accepted in the United States (U.S. GAAP) and International Financial Reporting Standards (IFRS). The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

In April 2014, the Financial Accounting Standards Board issued Update 2014-08 - Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB's and the International Accounting Standard Board's (IASB) reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

NOTE 19—SUBSEQUENT EVENT:

On July 29, 2014, CONSOL Energy closed on the private placement of $250,000 of 5.875% senior notes due 2022. The notes were an add-on to the $1,600,000 of 5.875% senior notes due 2022 that closed on April 16, 2014, collectively these will represent $1,850,000 of 5.875% senior notes due 2022 (the “Notes”). The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy intends to use the net proceeds of the sale of the add-on notes to repurchase a portion of the $1,250,000 of 8.25% senior notes due 2020 and for general corporate purposes.

The notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and, unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and the rules promulgated thereunder and applicable state securities laws. The Notes were offered only to qualified institutional buyers in reliance on Rule 144A under the Securities Act and non-U.S. persons in transactions outside the United States in reliance on Regulation S under the Securities Act.


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

General

E&P Marketing and Transportation Update:

Second quarter 2014 average dry gas prices, including the impact of our hedging program and net of basis, averaged $4.10 per Mcf. CONSOL Energy's expansion into wet gas production areas provided a liquids value uplift of $0.34 per Mcfe, bringing the overall average sales price to $4.44 per Mcfe. Second quarter 2014 liquids volumes of 2.6 Bcfe were nearly five times greater than in the 2013 second quarter. CONSOL Energy will continue to experience liquids uplift on future average sales prices as additional wells are brought online in the liquid-rich areas of the Marcellus and Utica Shales.

Faster-than-expected replenishment of gas inventories and increasing Marcellus production have put downward pressure on gas prices. These factors have contributed to a decline in the NYMEX index price for natural gas along with the basis differentials for most Appalachian market sales points. CONSOL Energy continues to mitigate the effect of the current downward basis pressure by finding opportunities to optimize and diversify sales opportunities among our 80+ customers located in five index markets. In addition, CONSOL Energy continues to manage the impact of price volatility through an active hedge program.

CONSOL Energy continues to develop a diversified portfolio of firm transportation capacity options to support the three-year production growth plan. Primary production areas in Southwestern Pennsylvania, Northern West Virginia, and Eastern Ohio are served by a large concentration of existing pipeline infrastructure that provides capacity to move production to major gas markets. The company is negotiating with pipeline and utility companies to expand our market reach into the premium markets of the upper-Midwest/Canada and the Southeast.

The Company currently has a total of 1.3 Bcf per day of effective firm transportation capacity. This capacity is adequate for the remainder of 2014 and supports the majority of projected volumes for the three-year growth plan. This is comprised of 0.7 Bcf per day of firm capacity on existing pipelines, contracted volumes of 0.3 Bcf per day on several pipeline projects that will be completed over the next several years, and an additional 0.3 Bcf per day of long-term firm sales with major customers that have their own firm capacity. The average demand cost for the existing and committed firm capacity is approximately $0.24 per MMBtu.

In addition to firm transportation capacity, CONSOL Energy has developed a processing portfolio that supports the increasing volumes from our wet production areas. The company has agreements to support the processing of 129 MMcf per day of gross gas volumes growing to more than 380 MMcf per day in the next twelve months. These commitments are sufficient to cover projected processing requirements for the next two years. CONSOL Energy will continue to layer in processing capacity as needed to support the liquids development plan.

In addition to establishing a solid processing portfolio, CONSOL Energy is developing a diversified approach to managing ethane. The company has entered into supply agreements with INEOS Europe and is also contracted to supply volumes to Shell’s cracker plant in Monaca, PA. CONSOL Energy is actively negotiating to supply ethane to other proposed regional cracker facilities. In addition to term sales, the company executed several spot deals to move ethane to Mt. Belvieu via the ATEX pipeline. CONSOL will also realize ethane value through blending capabilities. The company recently constructed an ethane pipeline to bring ethane supplies to the McQuay station where it will be blended with significant volumes of dry gas blend stock. Employing this multi-faceted approach enables us to diversify the ethane portfolio and capitalizes on changes in ethane pricing.

Coal Marketing Update:

Production cuts continue to take place, both in the U.S. and elsewhere, and a better supply/demand balance will eventually occur in the market. CONSOL Energy currently expects to ship approximately 5 million tons of metallurgical (both low volatile and high volatile in 2014). This is 1 million tons lower than the projection the company made three months ago. Buchanan Mine shipped 0.95 million tons in the second quarter of 2014. CONSOL Energy has been very active in the domestic met market for 2015, and expects to increase its 2015 domestic sales of low vol by at least 50%. CONSOL Energy's sales efforts are aided by having the lowest cost low vol mine in the U.S. and by having a strong balance sheet.

Bailey Mine coal continues to have a place in the high volatile metallurgical market, even though the overall metallurgical market remains weak. CONSOL Energy will continue to ship tons where they create the most shareholder value. In the second quarter, 330,000 tons of Bailey production was sold into the high volatile metallurgical markets.

For 2014, CONSOL Energy has been able to consistently transport all Bailey Mine coal produced, even though there have been challenges with capacity in the US rail system. CONSOL Energy has been able to move these tons to market due to having dual rail access facilities that can load 130 car trains in less than 2 hours, and also because of efficient logistics coordination with both the Norfolk Southern and CSX railroads and our customers.

For 2015 and 2016, CONSOL Energy continues to successfully market Bailey Mine tons into target core markets. During the second quarter, nearly 5.0 million annual tons were committed for 2015, and 4.0 million tons were committed for 2016. An additional 9.0 million tons are currently under negotiation for 2015 and 2016.

CONSOL Energy 2014 - 2016 Guidance:

Third quarter gas production, net to CONSOL, is expected to be 59 – 61 Bcfe, while annual 2014 production guidance was recently raised to 225 – 235 Bcfe, from 215 – 235 Bcfe. CONSOL Energy expects its 2015 and 2016 annual gas production to grow by 30%.

Total hedged natural gas production in the 2014 third quarter is 41.7 Bcf, at an average price of $4.58 per Mcf. CONSOL uses a dual-track approach to its gas hedging. The company uses a formulaic approach to a base of hedges, but can decide to layer-in additional opportunistic hedges to capture value from price spikes. CONSOL does not expect to hedge more than 80% of its estimated natural gas production for any given year. The annual gas hedge position for three years is shown in the table below:

E&P DIVISION GUIDANCE



	2014	2015	2016
Total Yearly Production (Bcfe) / % growth	225-235	+30%	+30%
Volumes Hedged (Bcf),as of 6/17/14	159.9*	82.6	75.3
Average Hedge Price ($/Mcf)	$4.58	$4.07	$4.17

* Includes 1st Half 2014 Actual Settlements of 76.4 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




	Q3 2014	Q4 2014	2015	2016
Columbia (TCO)
Volume (Bcf)	10.7	10.7	35.9	39.4
Average Hedge Price ($/Mcf)	$4.02	$4.02	$3.86	$3.93
Dominion South (DTI)
Volume (Bcf)	1.7	1.7	-	-
Average Hedge Price ($/Mcf)	$5.31	$5.31	-	-

COAL DIVISION GUIDANCE

In coal, the low volatile guidance range for 2014 has again been lowered from that shown three months ago to reflect a deterioration in pricing. For 2015, the low vol guidance was left unchanged from the previous guidance on the assumption that pricing will improve from current levels.

The thermal guidance for 2014 has increased from the previous guidance due to the strong start in both sales and production. The company believes that generators will be busy replenishing inventories that were drawn down due to the cold winter, which should translate into additional thermal sales opportunities. For 2015, thermal guidance was left unchanged.



	Q3 2014		2014		2015
Est. Total Coal Sales	7.3 - 7.7		31 - 33		31 - 35
Tonnage: Firm	7.1		30.8		16.9
Price: Sold (firm)	$	62.76	$	63.73	$	65.86
Est. Low-Vol Met Sales	0.75 - 0.85		3.4 - 3.8		3.5 - 5.0
Tonnage: Firm	0.5		2.8		1.0
Est. High-Vol Met Sales	0.2		1.5		2.0
Tonnage: Firm	0.2		1.1		0.3
Est. Thermal Sales	6.35 - 6.65		26.1 - 27.7		25.5 - 28.0
Tonnage: Firm	6.4		26.9		15.6

Note: While most of the data in the table are single point estimates, the inherent uncertainty of markets and mining operations means that investors should consider a reasonable range around these estimates. CONSOL has chosen not to forecast prices for open tonnage due to ongoing customer negotiations. Firm tonnage is tonnage that is both sold and priced, and excludes collared tons. CONSOL Energy has sold additional coal volumes that are not yet priced. Those volumes are excluded from this table. There are no collared tons in 2014. Collared tons in 2015 are 1.4 million tons, with a ceiling of $67.10 per ton and a floor of $54.90 per ton. Not included in the category breakdowns are the thermal tons from equity affiliate Harrison Resources and high vol and thermal tons from Western Allegheny Energy (WAE). Harrison Resources has 0.1 million tons for Q3 2014, and 0.4 million tons for all of 2014 and 2015. WAE has 0.1 million tons for Q3 2014, and 0.5 million tons and 0.6 million tons for all of 2014, and 2015, respectively.

Coal Reserve Mid-Year Update:

In June 2014, CONSOL Energy completed a multi-year re-evaluation of its remaining Pittsburgh seam longwall mineable reserves utilizing mine plans and mining horizon assumptions specific to each mine/reserve. In prior years, reserves estimates were based on a fixed 70% mining recovery of the Pittsburgh seam main bench only. This reevaluation is primarily predicated on advances in mining technology which have increased both mine recovery and the recovery of additional coal above the Pittsburgh main seam and advances in mine planning and modeling technology allowing CONSOL Energy to estimate and capture these changes. As a direct result of this reevaluation, the company’s Pittsburgh Seam reserve tonnage increased by 442 million tons to 1.805 billion tons.

CONSOL Energy is also updating its re-evaluation of its Illinois Basin coal reserves. This study should be complete in the next few months.

Results of Operations

Three Months Ended June 30, 2014 Compared with Three Months Ended June 30, 2013

Net Loss Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $25 million, or a loss of $0.11 per diluted share, for the three months ended June 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $13 million, or a loss of $0.05 per diluted share, for the three months ended June 30, 2013. Net loss attributable to CONSOL Energy shareholders for the three months ended June 30, 2013 included income from continuing operations of $8 million, or income of $0.04 per diluted share, for the three months ended June 30, 2013 and a loss from discontinued operations of $21 million, or a loss of $0.09 per diluted share.

The total Exploration and Production (E&P) division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total E&P division contributed income of $23 million before income tax for the three months ended June 30, 2014 compared to a loss of $5 million before income tax for the three months ended June 30, 2013. Total E&P production was 51.9 Bcfe for the three months ended June 30, 2014 compared to 38.6 Bcfe for the three months ended June 30, 2013.

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)	2014			2013		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	1,919			368		1,551			421.5	%
Sales Volume (Mbbls)	320			61		259			424.6	%
Gross Price ($/Bbl)	$	55.56		$	59.28	$	(3.72	)	(6.3	)%
Gross Revenue	$	17,772		$	3,635	$	14,137		388.9	%

Oil:
Sales Volume (MMcfe)	181			139		42			30.2	%
Sales Volume (Mbbls)	30			23		7			30.4	%
Gross Price ($/Bbl)	$	95.10		$	82.56	$	12.54		15.2	%
Gross Revenue	$	2,867		$	1,910	$	957		50.1	%

Condensate:
Sales Volume (MMcfe)	479			34		445			1,308.8	%
Sales Volume (Mbbls)	80			6		74			1,233.3	%
Gross Price ($/Bbl)	$	94.92		$	80.88	$	14.04		17.4	%
Gross Revenue	$	7,585		$	452	$	7,133		1,578.1	%

GAS
Sales Volume (MMcf)	49,295			38,043		11,252			29.6	%
Sales Price ($/Mcf)	$	4.23		$	4.22	$	0.01		0.2	%
Hedging Impact ($/Mcf)	$	(0.13	)	$	0.15	$	(0.28	)	(186.7	)%
Gross Revenue including Hedging Impact	$	202,075		$	166,165	$	35,910		21.6	%

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



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Average Sales Price (per Mcfe)	$	4.44	$	4.46	$	(0.02	)	(0.4	)%
Average Costs (per Mcfe)	3.44		3.77		(0.33		)	(8.8	)%
Margin	$	1.00	$	0.69	$	0.31		44.9	%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $231 million for the three months ended June 30, 2014 compared to $172 million for the three months ended June 30, 2013. The increase was primarily due to the 34.4% increase in total volumes sold offset, in part, by the 0.4% decrease in average price per Mcfe. The decrease in average sales price was primarily due to the $0.28 per Mcf decrease resulting from various transactions relating to our hedging program. These financial 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. These financial hedges represented approximately 19.7 Bcf of our produced gas sales volumes for the three months ended June 30, 2013 at an average gain of $0.29 per Mcf. The decreases due to our hedging program were offset, in part, by a slight increase in general market prices and the increase in sales of NGLs and condensate.

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


•	The improvement in the unit costs is primarily due to the increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 46% of gas sales volume for the three months ended June 30, 2014 compared to 27% in the three months ended June 30, 2013


•	Lifting costs per unit decreased in the period-to-period comparison due to the increase in sales volumes. The decrease was offset, in part, by an increase in total dollars relating to higher salt water disposal, and well site maintenance costs.


•	Gathering expense per unit also decreased 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 total dollars related to an increase in firm transportation costs and increased processing fees associated with natural gas liquids.


•	Depreciation, depletion and amortization increased as the portion of production from higher investment cost segments continued to grow.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $120 million of earnings before income tax for the three months ended June 30, 2014 compared to $106 million for the three months ended June 30, 2013. The total coal division sold 8.5 million tons of coal produced from CONSOL Energy mines for the three months ended June 30, 2014 compared to 7.1 million tons for the three months ended June 30, 2013. Current period sales were comprised of 86% thermal and 14 % metallurgical. Prior period sales were comprised of 72% thermal and 28% metallurgical.

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,
	2014		2013		Variance			Percent Change
Average Sales Price per ton sold	$	62.43	$	69.93	$	(7.50	)	(10.7	)%
Average Costs of Goods Sold per ton	47.63		51.23		(3.60		)	(7.0	)%
Margin	$	14.80	$	18.70	$	(3.90	)	(20.9	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets, the oversupply of coal used in steelmaking, and lower thermal coal pricing due to the roll-off of some higher-priced legacy contracts. The coal division priced 1.5 million tons on the export market at an average sales price of $63.21 per ton for the three months ended June 30, 2014 compared to 1.8 million tons at an average price of $75.12 per ton for the three months ended June 30, 2013. All other tons were sold on the domestic market.

The decrease in the average cost of goods sold per ton was primarily attributable to the increase in tons sold, as well as the mix of volumes sold. A higher percentage of thermal coal was sold, which has a lower unit cost per ton compared to low volatile metallurgical coal. The decrease was offset, in part, by geologic issues at the Enlow Fork Mine and an equipment change-out at the Harvey Mine which led to higher thermal costs per ton.

The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the E&P or coal segment.

General and Administrative costs are allocated between divisions (E&P, Coal and Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and Administrative costs are excluded from the E&P and Coal unit costs above. Total General and Administrative costs were made up of the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Continuing Operations General and Administrative Expenses	$	26	$	21	$	5		23.8	%
Discontinued Operations General and Administrative Expenses	—		11		(11		)	(100.0	)%
Total Company General and Administrative Expense	$	26	$	32	$	(6	)	(18.8	)%

Overall, total Company General and Administrative Expenses have decreased $6 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of the five West Virginia coal mines.

Total Company long-term liabilities for continuing operations, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $52 million for the three months ended June 30, 2014 compared to $35 million for the three months ended June 30, 2013. The increase of $17 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in $21 million of expense during 2014 and $5 million of expense in 2013. Pension settlement expense is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. The pension settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for E&P or Coal. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation 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 increase.

TOTAL E&P SEGMENT ANALYSIS for the three months ended June 30, 2014 compared to the three months ended June 30, 2013:

The E&P segment contributed $23 million to earnings before income tax for the three months ended June 30, 2014 compared to a loss before income tax of $5 million in the three months ended June 30, 2013. Variances by the individual E&P segments are discussed below.



	For the Three Months Ended												Difference to Three Months Ended
	June 30, 2014												June 30, 2013
(in millions)	Marcellus		CBM		Shallow Oil and Gas			Other Gas			Total E&P		Marcellus		CBM			Shallow Oil and Gas			Other Gas			Total E&P
Sales:
Produced	$	105	$	81	$	26		$	18		$	230	$	59	$	(7	)	$	(8	)	$	15		$	59
Related Party	—		1		—			—			1		—		—			—			—			—
Total Outside Sales	105		82		26			18			231		59		(7		)	(8		)	15			59
Gas Royalty Interest	—		—		—			18			18		—		—			—			1			1
Purchased Gas	—		—		—			1			1		—		—			—			(1		)	(1		)
Other Income	—		—		—			12			12		—		—			—			1			1
Total Revenue and Other Income	105		82		26			49			262		59		(7		)	(8		)	16			60
Lifting	5		10		9			2			26		—		—			(1		)	2			1
Ad Valorem, Severance, and Other Taxes	4		3		2			1			10		3		—			(1		)	1			3
Gathering	24		26		6			2			58		14		(3		)	(3		)	1			9
E&P Direct Administrative, Selling & Other	9		3		1			1			14		3		1			(2		)	(1		)	1
Depreciation, Depletion and Amortization	28		22		13			8			71		16		(1		)	(2		)	5			18
General & Administration	—		—		—			16			16		—		—			—			6			6
Gas Royalty Interest	—		—		—			16			16		—		—			—			2			2
Purchased Gas	—		—		—			1			1		—		—			—			—			—
Exploration and Other Costs	—		—		—			4			4		—		—			—			(6		)	(6		)
Other Corporate Expenses	—		—		—			21			21		—		—			—			(2		)	(2		)
Interest Expense	—		—		—			2			2		—		—			—			—			—
Total Cost	70		64		31			74			239		36		(3		)	(9		)	8			32
Earnings Before Income Tax	$	35	$	18	$	(5	)	$	(25	)	$	23	$	23	$	(4	)	$	1		$	8		$	28

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $35 million to the total Company earnings before income tax for the three months ended June 30, 2014 compared to $12 million for the three months ended June 30, 2013.



	For the Three Months Ended June 30,
	2014			2013		Variance			Percent Change
Marcellus Gas - Gas Sales Volumes (Bcf)	22.0			10.0		12.0			120.0	%
NGLs Sales Volumes (Bcfe)*	1.6			0.4		1.2			300.0	%
Condensate Sales Volumes (Bcfe)*	0.2			—		0.2			100.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	23.8			10.4		13.4			128.8	%

Average Sales Price - Gas (Mcf)	$	4.09		$	4.25	$	(0.16	)	(3.8	)%
Hedging Impact - Gas (Mcf)	$	(0.10	)	$	0.04	$	(0.14	)	(350.0	)%
Average Sales Price - NGLs (Mcfe)*	$	9.11		$	10.14	$	(1.03	)	(10.2	)%
Average Sales Price - Condensate (Mcfe)*	$	13.70		$	13.62	$	0.08		0.6	%

Total Average Marcellus sales price (per Mcfe)	$	4.40		$	4.49	$	(0.09	)	(2.0	)%
Average Marcellus lifting costs (per Mcfe)	$	0.20		$	0.44	$	(0.24	)	(54.5	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.19		$	0.15	$	0.04		26.7	%
Average Marcellus gathering costs (per Mcfe)	$	0.99		$	0.95	$	0.04		4.2	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.37		$	0.63	$	(0.26	)	(41.3	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.19		$	1.19	$	—		—	%
Total Average Marcellus costs (per Mcfe)	$	2.94		$	3.36	$	(0.42	)	(12.5	)%
Average Margin for Marcellus (per Mcfe)	$	1.46		$	1.13	$	0.33		29.2	%

* 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 sales revenues were $105 million for the three months ended June 30, 2014 compared to $46 million for the three months ended June 30, 2013. The $59 million increase is primarily due to a 128.8% increase in total volumes sold offset, in part, by a 2.0% decrease in total average sales price in the period-to-period comparison. The 13.4 Bcfe increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program. The $0.09 per Mcfe decrease in Marcellus total average sales price was primarily the result of the $0.16 per Mcf decrease in gas market prices and a $0.14 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 17.3 Bcf of our produced Marcellus gas sales volumes for the three months ended June 30, 2014 at an average loss of $0.12 per Mcf. For the three months ended June 30, 2013, these financial hedges represented approximately 4.5 Bcf at an average gain of $0.10 per Mcf. The decrease in average sales price was also off-set by the additional 1.4 Bcfe or $0.21 per Mcfe of NGLs and condensate sales volumes.

Total costs for the Marcellus segment were $70 million for the three months ended June 30, 2014 compared to $34 million for the three months ended June 30, 2013. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $5 million for the three months ended June 30, 2014 and June 30, 2013. The decrease in unit costs primarily relates to the 128.8% increase in sales volumes during the current period.

•Marcellus ad valorem, severance and other taxes were $4 million for the three months ended June 30, 2014 compared to $1 million for the three months ended June 30, 2013. The increase in total dollars is primarily due to an increase in severance tax expense caused by the 128.8% increase in sales volumes during the current period offset, in part, by the 3.8% decrease in average gas sales prices, without the impact of hedging. The decrease in unit costs is due to the additional sales volumes and mix of volumes produced by state.

•Marcellus gathering costs were $24 million for the three months ended June 30, 2014 compared to $10 million for the three months ended June 30, 2013. Total dollars increased primarily due to an increase in processing fees associated with NGLs along with an increase in utilized firm transportation costs, which resulted in a $0.06 per Mcfe increase in average unit costs. The impact on average unit costs from this increase was offset, in part, by higher sales volumes.

•Marcellus direct administrative, selling and other costs were $9 million for the three months ended June 30, 2014 compared to $6 million for the three months ended June 30, 2013. Direct administrative, selling and other costs attributable to the total E&P divisions are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The decrease in unit costs was primarily due to the increase in volumes sold.

•Depreciation, depletion and amortization costs were $28 million for the three months ended June 30, 2014 compared to $12 million for the three months ended June 30, 2013. There was approximately $28 million, or $1.16 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2014. There was approximately $12 million, or $1.17 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2013. There was less than $1 million, or $0.03 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended June 30, 2014. There was less than $1 million, or $0.02 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended June 30, 2013.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $18 million to the total Company earnings before income tax for the three months ended June 30, 2014 compared to $22 million for the three months ended June 30, 2013.



	For the Three Months Ended June 30,
	2014			2013		Variance			Percent Change
CBM Gas - Gas Sales Volumes (Bcf)	19.7			20.8		(1.1		)	(5.3	)%

Average Sales Price - Gas (Mcf)	$	4.31		$	4.16	$	0.15		3.6	%
Hedging Impact - Gas (Mcf)	$	(0.19	)	$	0.10	$	(0.29	)	(290.0	)%

Total Average CBM sales price (per Mcf)	$	4.12		$	4.26	$	(0.14	)	(3.3	)%
Average CBM lifting costs (per Mcf)	$	0.49		$	0.48	$	0.01		2.1	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.14		$	0.13	$	0.01		7.7	%
Average CBM gathering costs (per Mcf)	$	1.33		$	1.40	$	(0.07	)	(5.0	)%
Average CBM direct administrative, selling & other costs (per Mcf)	$	0.13		$	0.10	$	0.03		30.0	%
Average CBM depreciation, depletion and amortization costs (per Mcf)	$	1.12		$	1.09	$	0.03		2.8	%
Total Average CBM costs (per Mcf)	$	3.21		$	3.20	$	0.01		0.3	%
Average Margin for CBM (per Mcf)	$	0.91		$	1.06	$	(0.15	)	(14.2	)%

CBM sales revenues were $82 million in the three months ended June 30, 2014 compared to $89 million for the three months ended June 30, 2013. The $7 million decrease was primarily due to a 3.3% decrease in total average sales price per Mcf and a 5.3% decrease in volumes sold. CBM sales volumes decreased 1.1 Bcf for the three months ended June 30, 2014 compared to the 2013 period primarily due to normal well declines without a corresponding offset of additional wells drilled since our current focus is on Marcellus production. The decline in wells drilled is also due to the decline in production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price decreased $0.14 per Mcf primarily due to a $0.29 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 18.5 Bcf of our produced CBM gas sales volumes for the three months ended June 30, 2014 at an average loss of $0.20 per Mcf. For the three months ended June 30, 2013, these financial hedges represented approximately 11.6 Bcf at an average gain of $0.18 per Mcf. The decrease resulting from the hedging program was offset, in part, due to a $0.15 per Mcf increase in gas market prices.

Total costs for the CBM segment were $64 million for the three months ended June 30, 2014 and $67 million for the three months ended June 30, 2013. The decrease in total dollars and slight increase in unit costs for the CBM segment was due to the following items:

•CBM lifting costs were $10 million for the three months ended June 30, 2014 and June 30, 2013. The $0.01 per Mcf increase in unit costs was due to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $3 million for the three months ended June 30, 2014 and June 30, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes.

•CBM gathering costs were $26 million for the three months ended June 30, 2014 compared to $29 million for the three months ended June 30, 2013. The decrease in total dollars and average per unit costs was due to lower power fees and lower transportation costs. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $3 million for the three months ended June 30, 2014 compared to $2 million for the three months ended June 30, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $22 million for the three months ended June 30, 2014 and $23 million for the three months ended June 30, 2013. There was approximately $15 million, or $0.74 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2014. The production portion of

depreciation, depletion and amortization was $16 million, or $0.75 per unit-of-production in the three months ended June 30, 2013. There was approximately $7 million, or $0.38 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended June 30, 2014. The non-production related depreciation, depletion and amortization was $7 million, or $0.34 per Mcf for the three months ended June 30, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $5 million for the three months ended June 30, 2014 compared to a loss before income tax of $6 million for the three months ended June 30, 2013.



	For the Three Months Ended June 30,
	2014			2013			Variance			Percent Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)	5.7			6.6			(0.9		)	(13.6	)%
Oil Sales Volumes (Bcfe)*	0.1			0.1			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	5.8			6.7			(0.9		)	(13.4	)%

Average Sales Price - Gas (Mcf)	$	4.41		$	4.36		$	0.05		1.1	%
Hedging Impact - Gas (Mcf)	$	(0.08	)	$	0.49		$	(0.57	)	(116.3	)%
Average Sales Price - Oil (Mcfe)*	$	15.96		$	13.44		$	2.52		18.8	%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	4.58		$	5.00		$	(0.42	)	(8.4	)%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.50		$	1.46		$	0.04		2.7	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)	$	0.38		$	0.43		$	(0.05	)	(11.6	)%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.09		$	1.36		$	(0.27	)	(19.9	)%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.21		$	0.34		$	(0.13	)	(38.2	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.28		$	2.24		$	0.04		1.8	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.46		$	5.83		$	(0.37	)	(6.3	)%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.88	)	$	(0.83	)	$	(0.05	)	(6.0	)%

*Oil, 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.

Shallow Oil and Gas sales revenues were $26 million for the three months ended June 30, 2014 and $34 million for the three months ended June 30, 2013. The $8 million decrease was due to a 13.4% decrease in total volumes sold and a 8.4% decrease in the total average sales price. The decrease in total volumes sold was primarily due to normal well declines. The decrease in shallow oil and gas total average sales price was primarily the result of a $0.57 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 4.1 Bcf of our produced shallow oil and gas sales volumes for the three months ended June 30, 2014 at an average loss of $0.11 per Mcf. For the three months ended June 30, 2013, these financial hedges represented approximately 3.6 Bcf at an average gain of $0.92 per Mcf. The decrease in average sales price resulting from our hedging program was offset, in part, by a $0.05 per Mcf increase in average gas market prices.

Total costs for the shallow oil and gas segment were $31 million for the three months ended June 30, 2014 compared to $40 million for the three months ended June 30, 2013. The decrease in total dollars and unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $9 million for the three months ended June 30, 2014 compared to $10 million for the three months ended June 30, 2013. The $1 million decrease in total dollars is primarily due to lower accretion expense on the well plugging liability. Unit costs were negatively impacted by the decrease in gas sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes were $2 million for the three months ended June 30, 2014 compared to $3 million for the three months ended June 30, 2013. The $1 million decease in total dollars is primarily due to

decrease in gas sales volumes offset, in part, by the increase in average sales price during the current period. The improvement in unit costs was offset, in part, by the decrease in gas sales volumes.

•Shallow Oil and Gas gathering costs were $6 million for the three months ended June 30, 2014 compared to $9 million for the three months ended June 30, 2013. Gathering costs decreased $3 million primarily due to lower firm transportation costs in the period-to-period comparison. The improvement in unit costs was offset, in part, by the decrease in gas sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $1 million for the three months ended June 30, 2014 compared to $3 million for the three months ended June 30, 2013. The $2 million decrease in the period-to-period comparison was due to Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. These decreases in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $13 million for the three months ended June 30, 2014 compared to $15 million for the three months ended June 30, 2013. There was approximately $11 million, or $1.97 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2014. There was approximately $13 million, or $2.01 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2013. There was approximately $2 million, or $0.31 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2014. There was $2 million, or $0.23 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2013.

OTHER GAS SEGMENT

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

Other gas sales volumes are primarily related to production from the the Utica Shale in Ohio and the Chattanooga Shale in Tennessee. Revenue from these operations was approximately $18 million for the three months ended June 30, 2014 and $3 million for the three months ended June 30, 2013. Total costs related to these other sales were $14 million for the three months ended June 30, 2014 compared to $6 million for the three months ended June 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and the Chattanooga Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas sales revenue was $18 million for the three months ended June 30, 2014 compared to $17 million for the three months ended June 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.9		3.9		1.0			25.6	%
Average Sales Price Per thousand cubic feet	$	3.76	$	4.31	$	(0.55	)	(12.8	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $1 million for the three months ended June 30, 2014 compared to $2 million for the three months ended June 30, 2013.



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.3		0.4		(0.1		)	(25.0	)%
Average Sales Price Per thousand cubic feet	$	4.40	$	3.96	$	0.44		11.1	%

Other income was $12 million for the three months ended June 30, 2014 compared to $11 million for the three months ended June 30, 2013. The $1 million increase was primarily due to the following items:


•	Earnings from our equity affiliates increased $6 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Parties of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.


•	Interest income decreased $4 million due to the scheduled collection of the final installment in 2013 on the notes receivable from the 2011 Noble joint venture transaction.


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

General and Administrative costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $16 million for the three months ended June 30, 2014 compared to $10 million for the three months ended June 30, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income Loss Attributable to CONSOL Energy Shareholders" of this quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas costs were $16 million for the three months ended June 30, 2014 compared to $14 million for the three months ended June 30, 2013. 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,
	2014		2013		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.9		3.9		1.0			25.6	%
Average Cost Per thousand cubic feet sold	$	3.20	$	3.43	$	(0.23	)	(6.7	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million for the three months ended June 30, 2014 and June 30, 2013.



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.3		0.4		(0.1		)	(25.0	)%
Average Cost Per thousand cubic feet sold	$	3.32	$	2.99	$	0.33		11.0	%

Exploration and other costs were $4 million for the three months ended June 30, 2014 compared to $10 million for the three months ended June 30, 2013. The $6 million decrease is due to the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Marcellus Title Defects	$	—	$	2	$	(2	)	(100.0	)%
Lease Expiration Costs	1		3		(2		)	(66.7	)%
Land Rentals	1		2		(1		)	(50.0	)%
Other	2		3		(1		)	(33.3	)%
Total Exploration and Other Costs	$	4	$	10	$	(6	)	(60.0	)%


•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $2 million for the three months ended June 30, 2013.


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics. The $2 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.


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


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

Other corporate expenses were $21 million for the three months ended June 30, 2014 compared to $23 million for the three months ended June 30, 2013. The $2 million decrease was made up of the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Stock-based Compensation	$	4	$	5	$	(1	)	(20.0	)%
Short-term Incentive Compensation	5		5		—			—	%
Bank Fees	2		2		—			—	%
Unutilized Firm Transportation and Processing Fees	10		9		1			11.1	%
Other	—		2		(2		)	(100.0	)%
Total Other Corporate Expenses	$	21	$	23	$	(2	)	(8.7	)%


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


•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for, among other things, safety, production and unit costs. Short-term incentive compensation expense remained consistent in the period-to-period comparison.


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


•	Unutilized firm transportation costs and processing fees represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The $1 million increase is primarily due to increased firm transportation capacity which has not been utilized by active operations.


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

Interest expense related to the gas segment remained consistent at $2 million for the three months ended June 30, 2014 and June 30, 2013.

TOTAL COAL SEGMENT ANALYSIS for the three months ended June 30, 2014 compared to the three months ended June 30, 2013:

The coal segment contributed $120 million of earnings before income tax in the three months ended June 30, 2014 compared to $106 million in the three months ended June 30, 2013. Variances by the individual coal segments are discussed below.



	For the Three Months Ended														Difference to Three Months Ended
	June 30, 2014														June 30, 2013
(in millions)	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	446		$	20	$	67		$	—		$	533		$	110		$	(33	)	$	(44	)	$	—		$	33
Purchased Coal	—			—		—			3			3			—			—			—			(2		)	(2		)
Total Outside Sales	446			20		67			3			536			110			(33		)	(44		)	(2		)	31
Freight Revenue	—			—		—			10			10			—			—			—			—			—
Other Income	—			3		—			54			57			(1		)	2			—			11			12
Total Revenue and Other Income	446			23		67			67			603			109			(31		)	(44		)	9			43
Costs and Expenses:
Beginning inventory costs	20			—		12			—			32			(13		)	—			4			—			(9		)
Total direct operating costs	208			10		36			31			285			55			(14		)	(16		)	3			28
Total royalty/production taxes	22			1		4			—			27			5			(1		)	(3		)	—			1
Total direct services to operations	32			1		4			22			59			(2		)	(3		)	(2		)	(13		)	(20		)
Total retirement and disability	22			1		5			1			29			7			(1		)	(2		)	(2		)	2
Depreciation, depletion and amortization	42			2		9			12			65			13			(3		)	—			—			10
Ending inventory costs	(12		)	—		(12		)	—			(24		)	20			—			(3		)	—			17
Total Costs and Expenses	334			15		58			66			473			85			(22		)	(22		)	(12		)	29
Freight Expense	—			—		—			10			10			—			—			—			—			—
Total Costs	334			15		58			76			483			85			(22		)	(22		)	(12		)	29
Earnings (Loss) Before Income Taxes	$	112		$	8	$	9		$	(9	)	$	120		$	24		$	(9	)	$	(22	)	$	21		$	14

THERMAL COAL SEGMENT

The thermal coal segment contributed $112 million to total Company earnings before income tax for the three months ended June 30, 2014 and $88 million for the three months ended June 30, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	7.3		5.2		2.1			40.4	%
Average Sales Price Per Thermal Ton Sold	$	61.39	$	64.94	$	(3.55	)	(5.5	)%

Beginning Inventory Costs Per Thermal Ton	$	43.57	$	50.86	$	(7.29	)	(14.3	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	29.56	$	30.19	$	(0.63	)	(2.1	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	3.09		3.41		(0.32		)	(9.4	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.61		6.64		(2.03		)	(30.6	)%
Total Retirement and Disability Per Thermal Ton Produced	3.21		2.87		0.34			11.8	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.97		5.60		0.37			6.6	%
Total Production Costs Per Thermal Ton Produced	$	46.44	$	48.71	$	(2.27	)	(4.7	)%

Ending Inventory Costs Per Thermal Ton	$	56.82	$	57.47	$	(0.65	)	(1.1	)%

Total Costs Per Thermal Ton Sold	$	45.96	$	48.04	$	(2.08	)	(4.3	)%
Average Margin Per Thermal Ton Sold	$	15.43	$	16.90	$	(1.47	)	(8.7	)%

Thermal coal revenue was $446 million for the three months ended June 30, 2014 compared to $336 million for the three months ended June 30, 2013. The $110 million increase was attributable to a 2.1 million increase in tons sold offset, in part, by a $3.55 per ton lower average sales price. The decrease in average sales price was also attributable to 0.5 million tons of thermal coal being priced on the export market at an average sales price of $70.67 per ton for the three months ended June 30, 2014 compared to 0.3 million tons at an average price of $71.34 per ton for the three months ended June 30, 2013. Thermal coal pricing was also lower due to the roll-off of some higher-priced legacy sales contracts.

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

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. The costs of tons produced include items such as direct operating costs, royalty and production taxes, direct services to operations, retirement and disability, and depreciation, depletion, and amortization costs. Total cost of goods sold for thermal coal was $334 million for the three months ended June 30, 2014, or $85 million higher than the $249 million for the three months ended June 30, 2013. Total cost of goods sold for thermal coal was $45.96 per ton in the three months ended June 30, 2014 compared to $48.04 per ton in the three months ended June 30, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 40.4% increase in thermal tons sold. Fixed costs are allocated over more tons, resulting in lower unit costs. These improvements were offset, in part, by various maintenance projects at Bailey Mine related to a longwall overhaul. The increase in volumes was offset, in part, by geological conditions at Enlow Fork Mine along with geological conditions and equipment issues at the Harvey Mine.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $8 million to total Company earnings before income tax for the three months ended June 30, 2014 compared to $17 million for the three months ended June 30, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.3		0.8		(0.5		)	(62.5	)%
Average Sales Price Per High Vol Met Ton Sold	$	61.00	$	63.29	$	(2.29	)	(3.6	)%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	28.88	$	28.99	$	(0.11	)	(0.4	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	3.01		2.62		0.39			14.9	%
Total Direct Services to Operations Per High Vol Met Ton Produced	4.43		4.95		(0.52		)	(10.5	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.35		2.78		0.57			20.5	%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	6.34		5.51		0.83			15.1	%
Total Production Costs Per High Vol Met Ton Produced	$	46.01	$	44.85	$	1.16		2.6	%

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

Total Costs Per High Vol Met Ton Sold	$	46.01	$	44.85	$	1.16		2.6	%
Margin Per High Vol Met Ton Sold	$	14.99	$	18.44	$	(3.45	)	(18.7	)%

High volatile metallurgical coal revenue was $20 million for the three months ended June 30, 2014 compared to $53 million for the three months ended June 30, 2013. Average sales prices for high volatile metallurgical coal decreased $2.29 per ton in the period-to-period comparison. CONSOL Energy priced 0.3 million tons of high volatile metallurgical coal in the export market at an average sales price of $60.84 per ton for the three months ended June 30, 2014 compared to 0.8 million tons at an average price of $61.53 per ton for the three months ended June 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

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

Total cost of goods sold for high volatile metallurgical coal was $15 million for the three months ended June 30, 2014, or $22 million lower than the $37 million for the three months ended June 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $46.01 per ton in the three months ended June 30, 2014 compared to $44.85 per ton in the three months ended June 30, 2013. The decrease in total dollars and increase in unit costs is due to lower tons sold in the period-to-period comparison.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $9 million to total Company earnings before income tax in the three months ended June 30, 2014 compared to $31 million in the three months ended June 30, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Three Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	0.9		1.1		(0.2		)	(18.2	)%
Average Sales Price Per Low Vol Met Ton Sold	$	71.02	$	97.54	$	(26.52	)	(27.2	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	65.47	$	85.60	$	(20.13	)	(23.5	)%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	36.94	$	44.31	$	(7.37	)	(16.6	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	4.43		5.97		(1.54		)	(25.8	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	4.24		4.85		(0.61		)	(12.6	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.19		5.56		(0.37		)	(6.7	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	9.44		7.95		1.49			18.7	%
Total Production Costs Per Low Vol Met Ton Produced	$	60.24	$	68.64	$	(8.40	)	(12.2	)%

Ending Inventory Costs Per Low Vol Met Ton	$	60.96	$	64.76	$	(3.80	)	(5.9	)%

Total Costs Per Low Vol Met Ton Sold	$	61.15	$	70.46	$	(9.31	)	(13.2	)%
Margin Per Low Vol Met Ton Sold	$	9.87	$	27.08	$	(17.21	)	(63.6	)%

Low volatile metallurgical coal revenue was $67 million for the three months ended June 30, 2014 compared to $111 million for the three months ended June 30, 2013. The $44 million decrease was attributable to a $26.52 per ton lower average sales price and a 0.2 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market and the oversupply of coal used in steelmaking. CONSOL Energy priced 0.7 million tons of low volatile metallurgical coal in the export market at an average sales price of $59.05 per ton for the three months ended June 30, 2014 compared to 0.8 million tons at an average price of $89.02 per ton for the three months ended June 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold for low volatile metallurgical coal was $58 million for the three months ended June 30, 2014, or $22 million lower than the $80 million for the three months ended June 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $61.15 per ton in the three months ended June 30, 2014 compared to $70.46 per ton in the three months ended June 30, 2013. The decrease in total dollars and unit costs per low volatile metallurgical ton was primarily due to lower royalty and production taxes, lower wage and wage related expenses, and lower gas well plugging costs. These decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. These improvements were offset, in part, by lower tons sold.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $9 million for the three months ended June 30, 2014 compared to a loss before income tax of $30 million for the three months ended June 30, 2013. The other coal segment includes purchased coal activities and idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications and coal purchased from third parties and sold directly to our customers. The revenues were $3 million for the three months ended June 30, 2014 compared to $5 million for the three months ended June 30, 2013.

Miscellaneous other income was $54 million for the three months ended June 30, 2014 compared to $43 million for the three months ended June 30, 2013. The change is due to the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance
Coal Contract Buy Out	$	30	$	—	$	30
Rental Income	11		1		10
Royalty Income	4		5		(1		)
Equity in earnings of affiliates	5		9		(4		)
Gain on Sale of Assets	—		25		(25		)
Other	4		3		1
Total Other Income Coal Segment	$	54	$	43	$	11


•	For the three months ended June 30, 2014, $30 million of income was related to a coal customer contract buyout. The discontinued contract was a long term contract that created pricing risks for both parties. The parties agreed to an amicable settlement and anticipate a continued relationship in the future. No such transactions were entered into in the three months ended June 30, 2013.


•	Rental income increased $10 million due to equipment subleased to a third-party. These arrangements began in December 2013.


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


•	Equity in earnings of affiliates decreased $4 million due to various transactions completed by our equity partners, none of which were individually material.


•	Gain on sale of assets decreased $25 million primarily due to the sale of Potomac coal reserves in the three months ended June 30, 2013. No such transactions were entered into in the three months ended June 30, 2014.


•	Other increased $1 million due to various items, none of which were individually significant.

Other coal segment total costs were $76 million for the three months ended June 30, 2014 compared to $88 million for the three months ended June 30, 2013. The decrease of $12 million was primarily due to the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance
Closed and Idle Mines	$	14	$	30	$	(16	)
Purchased Coal	5		10		(5		)
General and Administrative Expense	10		10		—
Stock-based and Incentive Compensation	12		12		—
Freight Expense	10		10		—
Depreciation, Depletion, and Amortization	7		7		—
Lease Rental Expense	7		—		7
Other	11		9		2
Total Other Coal Segment Costs	$	76	$	88	$	(12	)

•

Closed and idle mine costs decreased approximately $16 million for the three months ended June 30, 2014 compared to the three months ended June 30, 2013. This was due to a $14 million decrease in asset retirement obligations, primarily at the Fola Mining Complex. The remaining $2 million decrease was due to various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material.


•	Purchased coal costs decreased $5 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.


•	General and Administrative Expense related to the other coal segment remained consistent in the period-to-period comparison. Refer to the discussion of total general and administrative costs contained in the section entitled "Net Loss Attributable to CONSOL Energy Shareholders" of this quarterly report for detailed cost explanations.


•	Stock-based and Incentive Compensation remained consistent in the period-to-period comparison.

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue and remained consistent in the period-to-period comparison.


•	Depreciation, Depletion, and Amortization remained consistent in the period-to-period comparison.


•	Lease rental expense increased $7 million primarily due to equipment leases that are subleased to a third-party. The third-party subleases began in December 2013.


•	Other expenses related to the Other Coal segment increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the three months ended June 30, 2014 compared to the three months ended June 30, 2013:

The other segment includes activity from the sales of industrial supplies, coal terminal activity and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $165 million for the three months ended June 30, 2014 compared to a loss before income tax of $60 million for the three months ended June 30, 2013. The other segment also includes total Company income tax expense of $1 million for the three months ended June 30, 2014 compared to an income tax expense of $30 million for the three months ended June 30, 2013.



	For the Three Months Ended June 30,
(in millions)	2014			2013			Variance			Percent Change
Sales—Outside	$	70		$	65		$	5		7.7	%
Other Income	2			3			(1		)	(33.3	)%
Total Revenue	72			68			4			5.9	%
Cost of Goods Sold and Other Charges	100			74			26			35.1	%
Depreciation, Depletion & Amortization	1			1			—			—	%
Loss on Debt Extinguishment	74			—			74			100.0	%
Interest Expense	62			53			9			17.0	%
Total Costs	237			128			109			85.2	%
Loss Before Income Tax	(165		)	(60		)	(105		)	175.0	%
Income Tax	1			30			(29		)	(96.7	)%
Net Loss	$	(166	)	$	(90	)	$	(76	)	(84.4	)%

Industrial supplies:

Outside Sales from industrial supplies were $60 million for the three months ended June 30, 2014 compared to $54 million for the three months ended June 30, 2013. The increase of $6 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $60 million for the three months ended June 30, 2014 compared to $53 million for the three months ended June 30, 2013. The increase of $7 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Coal terminal activity:

Outside Sales from terminal activity were $10 million for the three months ended June 30, 2014 compared to $11 million for the three months ended June 30, 2013. The decrease of $1 million was primarily attributable to decreased thru-put volumes for the quarter.

Total costs related to terminal activity were $7 million for the three months ended June 30, 2014 compared to $9 million for the three months ended June 30, 2013. Costs decreased $2 million due to lower per ton thru-put costs and a decrease in thru-put volumes.

Miscellaneous other:

Additional other income of $2 million was recognized for the three months ended June 30, 2014 compared to $3 million for the three months ended June 30, 2013. The $1 million decrease is due to various items in both periods, none of which were individually material.

Other corporate costs were $170 million for the three months ended June 30, 2014 compared to $66 million for the three months ended June 30, 2013. Other corporate costs increased due to the following items:



	For the Three Months Ended June 30,
(in millions)	2014		2013		Variance
Loss on Debt Extinguishment	$	74	$	—	$	74
Pension Settlement	21		5		16
Interest Expense	62		53		9
Revolver Modification Fees	3		—		3
Bank Fees	4		4		—
Other	6		4		2
	$	170	$	66	$	104


•	Loss on Debt Extinguishment 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 2017 at an average premium of 1.04%. No such transactions occurred in the prior period.

•

Pension settlement expense is required when the lump sum distributions made for a given plan year exceeds the total of the service and interest costs for that same plan year. Settlement accounting was triggered in both periods. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation 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 increase.


•	Interest expense increased $9 million due to a decrease in capitalized interest in the current period. The decrease in capitalized interest relates to the completion of several capital projects at the Bailey Complex.


•	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.


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

Income Taxes:

The effective income tax rate was (5.1)% for the three months ended June 30, 2014 compared to 77.5% for the three months ended June 30, 2013. The effective rates for the three months ended June 30, 2014 and 2013 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. The relationship between pre-tax earnings and percentage depletion also impacts the effective tax rate. 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 income 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)	2014			2013			Variance			Percent Change
Total Company Earnings Before Income Tax	$	(24	)	$	38		$	(62	)	(162.6	)%
Income Tax Expense (Benefit)	$	1		$	30		$	(29	)	(98.1	)%
Effective Income Tax Rate	(5.1		)%	77.5		%	(82.6		)%

Results of Operations

Six Months Ended June 30, 2014 Compared with Six Months Ended June 30, 2013

Net Income (Loss) Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $91 million, or income of $0.39 per diluted share, for the six months ended June 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $14 million, or a loss of $0.06 per diluted share, for the six months ended June 30, 2013. Included in net income was income from continuing operations of $97 million, or income of $0.42 per diluted share, for the six months ended June 30, 2014. Income from continuing operations was $5 million, or $0.02 per diluted share, for the six months ended June 30, 2013. Also included in net income is a loss from discontinued operations of $6 million, or a loss of $0.03 per diluted share, for the six months ended June 30, 2014. There was a loss from discontinued operations of $19 million, or a loss of $0.08 per diluted share, for the six months ended June 30, 2013.

The total Exploration and Production (E&P) division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total E&P division contributed income of $101 million before income tax for the six months ended June 30, 2014 compared to a loss of $5 million before income tax for the six months ended June 30, 2013. Total E&P production was 100.3 Bcfe for the six months ended June 30, 2014 compared to 77.8 Bcfe for the six months ended June 30, 2013.

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)	2014			2013		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	3,488			765		2,723			355.9	%
Sales Volume (Mbbls)	581			128		453			353.9	%
Gross Price ($/Bbl)	$	51.96		$	54.66	$	(2.7	)	(4.9	)%
Gross Revenue	$	30,196		$	6,968	$	23,228		333.4	%

Oil:
Sales Volume (MMcfe)	327			267		60			22.5	%
Sales Volume (Mbbls)	55			45		10			22.2	%
Gross Price ($/Bbl)	$	92.88		$	80.82	$	12.06		14.9	%
Gross Revenue	$	5,058		$	3,592	$	1,466		40.8	%

Condensate:
Sales Volume (MMcfe)	775			115		660			573.9	%
Sales Volume (Mbbls)	129			19		110			578.9	%
Gross Price ($/Bbl)	$	85.56		$	79.38	$	6.18		7.8	%
Gross Revenue	$	11,054		$	1,524	$	9,530		625.3	%

GAS
Sales Volume (MMcf)	95,683			76,665		19,018			24.8	%
Sales Price ($/Mcf)	$	4.95		$	3.90	$	1.05		26.9	%
Hedging Impact ($/Mcf)	$	(0.23	)	$	0.39	$	(0.62	)	(159.0	)%
Gross Revenue including Hedging Impact	$	451,186		$	328,756	$	122,430		37.2	%

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



	For the Six Months Ended June 30,
	2014		2013		Variance			Percent Change
Average Sales Price (per Mcfe)	$	4.96	$	4.38	$	0.58		13.2	%
Average Costs (per Mcfe)	3.53		3.65		(0.12		)	(3.3	)%
Margin	$	1.43	$	0.73	$	0.70		95.9	%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $497 million for the six months ended June 30, 2014 compared to $341 million for the six months ended June 30, 2013. The increase was primarily due to the 28.9% increase in total volumes sold, along with a 13.2% increase in average price per Mcfe. The increase in average sales price is the result of an increase in general market prices and the increase in sales of NGLs and condensate. The increase was offset, in part, by the $0.62 per Mcf decrease resulting from various transactions relating to our hedging program.. These financial 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. These financial hedges represented approximately 36.3 Bcf of our produced gas sales volumes for the six months ended June 30, 2013 at an average gain of $0.81 per Mcf.

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


•	The improvement in the unit costs is primarily due to the 28.9% increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 44% of gas sales volume for the six months ended June 30, 2014 compared to 27% in the six months ended June 30, 2013.


•	Lifting costs per unit decreased in the period-to-period comparison due to the increase in sales volumes. The decrease was offset, in part, by an increase in total dollars relating to higher salt water disposal, well site maintenance costs, and costs related to wells operated by our joint-venture partners.


•	Gathering expense per unit also decreased 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 total dollars related to an increase in firm transportation costs and increased processing fees associated with NGLs.


•	Ad valorem, severance, and other taxes increased in the period-to-period comparison due to the higher average gas sales price, without the impact of hedging, which is the primary basis for severance tax. The increase is also related to the increase in volumes sold and the mix of volumes by state.


•	Depreciation, depletion and amortization increased as the portion of production from higher investment cost segments continued to grow.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $227 million of earnings before income tax for the six months ended June 30, 2014 compared to $205 million for the six months ended June 30, 2013. The total coal division sold 16.6 million tons of coal produced from CONSOL Energy mines for the six months ended June 30, 2014 compared to 14.7 million tons for the six months ended June 30, 2013. Current period sales were comprised of 83% thermal and 17% metallurgical. Prior period sales were comprised of 72% thermal and 28% metallurgical.

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,
	2014		2013		Variance			Percent Change
Average Sales Price per ton sold	$	64.26	$	71.09	$	(6.83	)	(9.6	)%
Average Costs of Goods Sold per ton	46.43		51.19		(4.76		)	(9.3	)%
Margin	$	17.83	$	19.90	$	(2.07	)	(10.4	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets, the oversupply of coal used in steelmaking, and lower thermal coal pricing due to the roll-off of some higher-priced legacy contracts. The coal division priced 3.4 million tons on the export market at an average sales price of $63.90 per ton for the six months ended June 30, 2014 compared to 4.2 million tons at an average price of $75.60 per ton for the six months ended June 30, 2013. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily attributable to the increase in tons sold, as well as the mix of volumes sold. A higher percentage of thermal coal was sold in the current period compared to the prior period. These tons had a lower unit cost per ton sold compared to low volatile metallurgical which lowered the overall average cost of the company.

The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the E&P or coal segment.



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Continuing Operations General and Administrative Expenses	$	57	$	40	$	17		42.5	%
Discontinued Operations General and Administrative Expenses	—		21		(21		)	(100.0	)%
Total Company General and Administrative Expense	$	57	$	61	$	(4	)	(6.6	)%

Overall, total Company General and Administrative Expenses have decreased $4 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of the five West Virginia coal mines.

Total Company long-term liabilities for continuing operations, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $80 million for the six months ended June 30, 2014 compared to $94 million for the six months ended June 30, 2013. The decrease of $14 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in a $21 million increase of expense during 2014 and a $32 million increase of expense in 2013. Pension settlement expense is required when lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. The pension settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for E&P or Coal. See Note 4 - Pension and Other Post-Employment Benefit Plans and Note 5 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation 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 decrease.

TOTAL E&P SEGMENT ANALYSIS for the six months ended June 30, 2014 compared to the six months ended June 30, 2013:

The E&P segment contributed $101 million to earnings before income tax for the six months ended June 30, 2014 compared to a loss before income tax of $5 million in the six months ended June 30, 2013. Variances by the individual E&P segments are discussed below.



	For the Six Months Ended												Difference to Six Months Ended
	June 30, 2014												June 30, 2013
(in millions)	Marcellus		CBM		Shallow Oil and Gas			Other Gas			Total E&P		Marcellus		CBM			Shallow Oil and Gas			Other Gas			Total E&P
Sales:
Produced	$	230	$	176	$	59		$	31		$	496	$	135	$	5		$	(7	)	$	24		$	157
Related Party	—		1		—			—			1		—		(1		)	—			—			(1		)
Total Outside Sales	230		177		59			31			497		135		4			(7		)	24			156
Gas Royalty Interest	—		—		—			45			45		—		—			—			14			14
Purchased Gas	—		—		—			5			5		—		—			—			2			2
Other Income	—		—		—			43			43		—		—			—			19			19
Total Revenue and Other Income	230		177		59			124			590		135		4			(7		)	59			191
Lifting	13		19		16			8			56		4		—			(1		)	6			9
Ad Valorem, Severance, and Other Taxes	7		6		5			2			20		4		2			—			2			8
Gathering	42		52		15			2			111		23		(6		)	(4		)	1			14
E&P Direct Administrative, Selling & Other	17		4		2			2			25		4		—			(2		)	—			2
Depreciation, Depletion and Amortization	57		44		28			14			143		31		(1		)	(2		)	9			37
General & Administration	—		—		—			33			33		—		—			—			12			12
Gas Royalty Interest	—		—		—			39			39		—		—			—			14			14
Purchased Gas	—		—		—			4			4		—		—			—			2			2
Exploration and Other Costs	—		—		—			7			7		—		—			—			(14		)	(14		)
Other Corporate Expenses	—		—		—			47			47		—		—			—			1			1
Interest Expense	—		—		—			4			4		—		—			—			—			—
Total Cost	136		125		66			162			489		66		(5		)	(9		)	33			85
Earnings Before Income Tax	$	94	$	52	$	(7	)	$	(38	)	$	101	$	69	$	9		$	2		$	26		$	106

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $94 million to the total Company earnings before income tax for the six months ended June 30, 2014 compared to $25 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
	2014			2013		Variance			Percent Change
Marcellus Gas - Gas Sales Volumes (Bcf)	41.3			20.2		21.1			104.5	%
NGLs Sales Volumes (Bcfe)*	2.9			0.7		2.2			314.3	%
Condensate Sales Volumes (Bcfe)*	0.3			0.1		0.2			200.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	44.5			21.0		23.5			111.9	%

Average Sales Price - Gas (Mcf)	$	5.04		$	3.97	$	1.07		27.0	%
Hedging Impact - Gas (Mcf)	$	(0.19	)	$	0.33	$	(0.52	)	(157.6	)%
Average Sales Price - NGLs (Mcfe)*	$	8.75		$	9.20	$	(0.45	)	(4.9	)%
Average Sales Price - Condensate (Mcfe)*	$	12.88		$	13.61	$	(0.73	)	(5.4	)%

Total Average Marcellus sales (per Mcfe)	$	5.16		$	4.51	$	0.65		14.4	%
Average Marcellus lifting costs (per Mcfe)	$	0.30		$	0.45	$	(0.15	)	(33.3	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.16		$	0.14	$	0.02		14.3	%
Average Marcellus gathering costs (per Mcfe)	$	0.94		$	0.89	$	0.05		5.6	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.37		$	0.60	$	(0.23	)	(38.3	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.28		$	1.22	$	0.06		4.9	%
Total Average Marcellus costs (per Mcfe)	$	3.05		$	3.30	$	(0.25	)	(7.6	)%
Average Margin for Marcellus (per Mcfe)	$	2.11		$	1.21	$	0.90		74.4	%

The Marcellus segment sales revenues were $230 million for the six months ended June 30, 2014 compared to $95 million for the six months ended June 30, 2013. The $135 million increase is primarily due to a 111.9% increase in total volumes sold, and a 14.4% increase in total average sales prices in the period-to-period comparison. The 23.5 Bcfe increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program. The $0.65 per Mcfe increase in Marcellus total average sales price was primarily the result of the $1.07 per Mcf increase in gas market prices, along with an additional 2.4 Bcfe of NGLs and condensate sales volumes. The increase was offset, in part, by a $0.52 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 31.3 Bcf of our produced Marcellus gas sales volumes for the six months ended June 30, 2014 at an average loss of $0.25 per Mcf. For the six months ended June 30, 2013, these financial hedges represented approximately 8.8 Bcf at an average gain of $0.74 per Mcf.

Total costs for the Marcellus segment were $136 million for the six months ended June 30, 2014 compared to $70 million for the six months ended June 30, 2013. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $13 million for the six months ended June 30, 2014 compared to $9 million for the six months ended June 30, 2013. The increase in total dollars primarily relates to additional volumes sold and an increase in salt water disposal costs, well tending costs, and costs related to wells operated by our joint-venture partners. The increase in total dollars were more than offset by the increase in gas sales volumes and resulted in an improvement in unit costs.

•Marcellus ad valorem, severance and other taxes were $7 million for the six months ended June 30, 2014 compared to $3 million for the six months ended June 30, 2013. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by the 27.0% increase in average gas sales prices, without the impact of hedging, and the additional sales volumes and mix of volumes produced by state.

•Marcellus gathering costs were $42 million for the six months ended June 30, 2014 compared to $19 million for the six months ended June 30, 2013. Total dollars increased primarily due to an increase in processing fees associated with NGLs along with an increase in utilized firm transportation costs, which resulted in a $0.05 per Mcfe increase in average unit costs.

•Marcellus direct administrative, selling and other costs were $17 million for the six months ended June 30, 2014 compared to $13 million for the six months ended June 30, 2013. 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. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The decrease in unit costs was primarily due to the increase in volumes sold.

•Depreciation, depletion and amortization costs were $57 million for the six months ended June 30, 2014 compared to $26 million for the six months ended June 30, 2013. There was approximately $56 million, or $1.25 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the six months ended June 30, 2014. There was approximately $25 million, or $1.19 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2013. There was approximately $1 million, or $0.03 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the six months ended June 30, 2014 and for the six months ended June 30, 2013.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $52 million to the total Company earnings before income tax for the six months ended June 30, 2014 compared to $43 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
	2014			2013		Variance			Percent Change
CBM Gas - Gas Sales Volumes (Bcf)	39.5			41.6		(2.1		)	(5.0	)%

Average Sales Price - Gas (Mcf)	$	4.81		$	3.86	$	0.95		24.6	%
Hedging Impact - Gas (Mcf)	$	(0.30	)	$	0.31	$	(0.61	)	(196.8	)%

Total Average CBM sales price (per Mcf)	$	4.51		$	4.17	$	0.34		8.2	%
Average CBM lifting costs (per Mcf)	$	0.48		$	0.46	$	0.02		4.3	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.17		$	0.09	$	0.08		88.9	%
Average CBM gathering costs (per Mcf)	$	1.31		$	1.39	$	(0.08	)	(5.8	)%
Average CBM direct administrative, selling & other costs (per Mcf)	$	0.12		$	0.09	$	0.03		33.3	%
Average CBM depreciation, depletion and amortization costs (per Mcf)	$	1.12		$	1.10	$	0.02		1.8	%
Total Average CBM costs (per Mcf)	$	3.20		$	3.13	$	0.07		2.2	%
Average Margin for CBM (per Mcf)	$	1.31		$	1.04	$	0.27		26.0	%

CBM sales revenues were $177 million in the six months ended June 30, 2014 compared to $173 million for the six months ended June 30, 2013. The $4 million increase was primarily due to a 8.2% increase in total average sales price per Mcf offset, in part, by a 5.0% decrease in total volumes sold. CBM sales volumes decreased 2.1 Bcf for the six months ended June 30, 2014 compared to the 2013 period. The decrease was primarily due to normal well declines without a corresponding offset of additional wells drilled since our current focus is on Marcellus production. The decline in wells drilled is also due to the decline in production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price increased $0.34 per Mcf due to a $0.95 per Mcf increase in average gas market prices. The increase was offset, in part, by a $0.61 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 35.2 Bcf of our produced CBM gas sales volumes for the six months ended June 30, 2014 at an average loss of $0.33 per Mcf. For the six months ended June 30, 2013, these financial hedges represented approximately 20.6 Bcf at an average gain of $0.62 per Mcf.

Total costs for the CBM segment were $125 million for the six months ended June 30, 2014 and $130 million for the six months ended June 30, 2013. The decrease in total dollars and increase in unit costs for the CBM segment was due to the following items:

•CBM lifting costs were $19 million for the six months ended June 30, 2014 and June 30, 2013. The $0.02 increase in unit costs was due to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $6 million for the six months ended June 30, 2014 compared to $4 million for the six months ended June 30, 2013. The increase of $2 million was due to an increase in severance tax expense resulting from the increase in average sales price, without the impact of hedging, as described above. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•CBM gathering costs were $52 million for the six months ended June 30, 2014 compared to $58 million for the six months ended June 30, 2013. The decrease in total dollars and average per unit costs was due to decreased compressor maintenance costs, decreased power fees, and a decrease in transportation costs. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $4 million for the six months ended June 30, 2014 and June 30, 2013. Unit costs were negatively impacted $0.03 per Mcf by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $44 million for the six months ended June 30, 2014 and $45 million for the six months ended June 30, 2013. There was approximately $30 million, or $0.77 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the six months ended June 30, 2014. The production portion of depreciation, depletion and amortization was $31 million, or $0.74 per unit-of-production in the six months ended June 30, 2013. There was approximately $14 million, or $0.35 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the six months ended June 30, 2014. The non-production related depreciation, depletion and amortization was $14 million, or $0.36 per Mcf for the six months ended June 30, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $7 million for the six months ended June 30, 2014 compared to a loss before income tax of $9 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
	2014			2013			Variance			Percent Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)	11.4			13.6			(2.2		)	(16.2	)%
Oil Sales Volumes (Bcfe)*	0.2			0.2			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	11.6			13.8			(2.2		)	(15.9	)%

Average Sales Price - Gas (Mcf)	$	5.07		$	3.92		$	1.15		29.3	%
Hedging Impact - Gas (Mcf)	$	(0.19	)	$	0.75		$	(0.94	)	(125.3	)%
Average Sales Price - Oil (Mcfe)*	$	15.18		$	11.84		$	3.34		28.2	%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	5.08		$	4.78		$	0.30		6.3	%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.40		$	1.22		$	0.18		14.8	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)	$	0.44		$	0.40		$	0.04		10.0	%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.27		$	1.38		$	(0.11	)	(8.0	)%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.19		$	0.33		$	(0.14	)	(42.4	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.37		$	2.15		$	0.22		10.2	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.67		$	5.48		$	0.19		3.5	%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.59	)	$	(0.70	)	$	0.11		15.7	%

Shallow Oil and Gas sales revenues were $59 million for the six months ended June 30, 2014 compared to $66 million for the six months ended June 30, 2013. The $7 million decrease is the result of a 15.9% decrease in total volumes sold, offset, in part, by a 6.3% increase in the total average sales price. The decrease in total volumes sold was primarily due to normal well declines in addition to some wells being shut-in in areas that have active Marcellus drilling. The increase in shallow oil and gas total average sales price was primarily the result of a $1.15 per Mcf increase in average gas market prices offset by a $0.94 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 7.7 Bcf of our produced shallow oil and gas sales volumes for the six months ended June 30, 2014 at an average loss of $0.28 per Mcf. For the six months ended June 30, 2013, these financial hedges represented approximately 6.8 Bcf at an average gain of $1.50 per Mcf.

Total costs for the shallow oil and gas segment were $66 million for the six months ended June 30, 2014 compared to $75 million for the six months ended June 30, 2013. The decrease in total dollars and increase in unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $16 million for the six months ended June 30, 2014 compared to $17 million for the six months ended June 30, 2013. The $1 million decrease in total dollars is primarily due to an decrease in accretion expense on the well plugging liability and a decrease in repair and maintenance costs. Unit costs were negatively impacted by the decrease in gas sales volumes, which resulted in an impairment.

•Shallow Oil and Gas ad valorem, severance and other taxes were $5 million for the six months ended June 30, 2014 and June 30, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes, which resulted in an impairment.

•Shallow Oil and Gas gathering costs were $15 million for the six months ended June 30, 2014 compared to $19 million for the six months ended June 30, 2013. Gathering costs decreased $4 million primarily due to a decrease in firm transportation costs in the period-to-period comparison. The decrease in total dollars was partial offset by the decrease in gas sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $2 million for the six months ended June 30, 2014 compared to $4 million for the six months ended June 30, 2013. The $2 million decrease in the period-to-period comparison was due to Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. The decrease in total dollars was partial offset by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $28 million for the six months ended June 30, 2014 compared to $30 million for the six months ended June 30, 2013. There was approximately $24 million, or $2.05 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2014. There was approximately $26 million, or $1.89 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2013. There was approximately $4 million, or $0.32 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the six months ended June 30, 2014. There was $4 million, or $0.26 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the six months ended June 30, 2013.

OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the the Utica Shale in Ohio and the Chattanooga Shale in Tennessee. Revenue from these operations was approximately $31 million for the six months ended June 30, 2014 compared to $7 million for the six months ended June 30, 2013. Total costs related to these other sales were $28 million for the six months ended June 30, 2014 compared to $10 million for the six months ended June 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and the Chattanooga Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas sales revenue was $45 million for the six months ended June 30, 2014 compared to $31 million for the six months ended June 30, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.



	For the Six Months Ended June 30,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	9.1		7.4		1.7		23.0	%
Average Sales Price Per thousand cubic feet	$	4.95	$	4.21	$	0.74	17.6	%

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, 2014 compared to $3 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
	2014		2013		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.7		0.7		—		—	%
Average Sales Price Per thousand cubic feet	$	7.23	$	3.69	$	3.54	95.9	%

Other income was $43 million for the six months ended June 30, 2014 compared to $24 million for the six months ended June 30, 2013. The $19 million increase was primarily due to the following items:


•	Other income increased $16 million primarily due to an increase in revenue related to certain gathering arrangements.


•	Earnings from our equity affiliates increased $9 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Parties of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.


•	Interest income decreased $8 million due to the scheduled collection of the final installment in 2013 on the notes receivable from the 2011 Noble joint venture transaction.


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

General and Administrative costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $33 million for the six months ended June 30, 2014 compared to $21 million for the six months ended June 30, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas costs were $39 million for the six months ended June 30, 2014 compared to $25 million for the six months ended June 30, 2013. 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,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	9.1		7.4		1.7		23.0	%
Average Cost Per thousand cubic feet sold	$	4.26	$	3.42	$	0.84	24.6	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $4 million for the six months ended June 30, 2014 compared to $2 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
	2014		2013		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.7		—		—	%
Average Cost Per thousand cubic feet sold	$	5.89	$	2.70	$	3.19	118.1	%

Exploration and other costs were $7 million for the six months ended June 30, 2014 compared to $21 million for the six months ended June 30, 2013. The $14 million decrease is due to the following items:



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Marcellus Title Defects	$	—	$	9	$	(9	)	(100.0	)%
Lease Expiration Costs	2		3		(1		)	(33.3	)%
Land Rentals	2		3		(1		)	(33.3	)%
Other	3		6		(3		)	(50.0	)%
Total Exploration and Other Costs	$	7	$	21	$	(14	)	(66.7	)%


•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $9 million for the six months ended June 30, 2013.


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics. The $1 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.


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


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

Other corporate expenses were $47 million for the six months ended June 30, 2014 compared to $46 million for the six months ended June 30, 2013. Other corporate expense was made up of the following items:



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance			Percent Change
Unutilized Firm Transportation and Processing Fees	$	21	$	16	$	5		31.3	%
Short-term Incentive Compensation	11		9		2			22.2	%
Bank Fees	4		3		1			33.3	%
Stock-based Compensation	10		14		(4		)	(28.6	)%
Other	1		4		(3		)	(75.0	)%
Total Other Corporate Expenses	$	47	$	46	$	1		2.2	%


•	Unutilized firm transportation and processing fees represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for NGLs. The $5 million increase is primarily due to increased firm transportation capacity which has not been utilized by active operations.


•	The short term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for, among other things, safety, production and unit costs. Short term incentive compensation expense was higher for the 2014 period compared to the 2013 period due to higher projected payouts.


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


•	Stock-based compensation decreased $4 million in the period-to-period comparison primarily due to a reduction in the non-cash amortization expense and less accelerated expense for retiree eligible employees under our current plans.


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

Interest expense related to the gas segment remained consistent at $4 million for the six months ended June 30, 2014 and June 30, 2013.

TOTAL COAL SEGMENT ANALYSIS for the six months ended June 30, 2014 compared to the six months ended June 30, 2013:

The coal segment contributed $227 million of earnings before income tax in the six months ended June 30, 2014 compared to $205 million in the six months ended June 30, 2013. Variances by the individual coal segments are discussed below.



	For the Six Months Ended														Difference to Six Months Ended
	June 30, 2014														June 30, 2013
(in millions)	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	864		$	49	$	151		$	—		$	1,064		$	183		$	(54	)	$	(107	)	$	—		$	22
Purchased Coal	—			—		—			7			7			—			—			—			(4		)	(4		)
Total Outside Sales	864			49		151			7			1,071			183			(54		)	(107		)	(4		)	18
Freight Revenue	—			—		—			20			20			—			—			—			(2		)	(2		)
Other Income	—			3		—			79			82			(1		)	1			—			23			23
Total Revenue and Other Income	864			52		151			106			1,173			182			(53		)	(107		)	17			39
Costs and Expenses:
Beginning inventory costs	21			—		11			—			32			(12		)	—			(10		)	—			(22		)
Total direct operating costs	381			23		81			69			554			71			(28		)	(21		)	15			37
Total royalty/production taxes	41			2		9			2			54			3			—			(5		)	2			—
Total direct services to operations	59			3		11			62			135			(5		)	(6		)	(1		)	(10		)	(22		)
Total retirement and disability	40			2		11			1			54			10			(3		)	(2		)	(5		)	—
Depreciation, depletion and amortization	74			5		19			23			121			16			(5		)	(1		)	(1		)	9
Ending inventory costs	(12		)	—		(12		)	—			(24		)	20			—			(3		)	—			17
Total Costs and Expenses	604			35		130			157			926			103			(42		)	(43		)	1			19
Freight Expense	—			—		—			20			20			—			—			—			(2		)	(2		)
Total Costs	604			35		130			177			946			103			(42		)	(43		)	(1		)	17
Earnings (Loss) Before Income Taxes	$	260		$	17	$	21		$	(71	)	$	227		$	79		$	(11	)	$	(64	)	$	18		$	22

THERMAL COAL SEGMENT

The thermal coal segment contributed $260 million to total Company earnings before income tax for the six months ended June 30, 2014 compared to $181 million for the six months ended June 30, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	13.7		10.5		3.2			30.5	%
Average Sales Price Per Thermal Ton Sold	$	63.16	$	64.70	$	(1.54	)	(2.4	)%

Beginning Inventory Costs Per Thermal Ton	$	50.82	$	50.86	$	(0.04	)	(0.1	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	28.13	$	29.74	$	(1.61	)	(5.4	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	3.05		3.63		(0.58		)	(16.0	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.41		6.12		(1.71		)	(27.9	)%
Total Retirement and Disability Per Thermal Ton Produced	2.99		2.88		0.11			3.8	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.48		5.53		(0.05		)	(0.9	)%
Total Production Costs Per Thermal Ton Produced	$	44.06	$	47.90	$	(3.84	)	(8.0	)%

Ending Inventory Costs Per Thermal Ton	$	56.82	$	57.47	$	(0.65	)	(1.1	)%

Total Costs Per Thermal Ton Sold	$	44.07	$	47.58	$	(3.51	)	(7.4	)%
Average Margin Per Thermal Ton Sold	$	19.09	$	17.12	$	1.97		11.5	%

Thermal coal revenue was $864 million for the six months ended June 30, 2014 compared to $681 million for the six months ended June 30, 2013. The $183 million increase was attributable to a 3.2 million increase in tons sold offset, in part, by a $1.54 per ton decrease in average sales price. Thermal coal pricing was lower because of the roll-off of some higher-priced legacy sales contracts. The decrease in price was offset, in part, due to 1.0 million tons of thermal coal being priced on the export market at an average sales price of $65.75 per ton for the six months ended June 30, 2014 compared to 0.9 million tons at an average price of $62.79 per ton for the six months ended June 30, 2013.

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. The costs of tons produced include items such as direct operating costs, royalty and production taxes, direct services to operations, retirement and disability, and depreciation, depletion, and amortization costs. Total cost of goods sold for thermal coal was $604 million for the six months ended June 30, 2014, or $103 million higher than the $501 million for the six months ended June 30, 2013. Total cost of goods sold for thermal coal was $44.07 per ton in the six months ended June 30, 2014 compared to $47.58 per ton in the six months ended June 30, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 30.5% increase in thermal tons sold. Fixed costs are allocated over more tons, resulting in lower unit costs. These improvements were offset, in part, by various maintenance projects at Bailey Mine related to a longwall overhaul. Unit costs were also impacted in the current period due to geological conditions at Enlow Fork Mine along with geological conditions and equipment issues at the Harvey Mine.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $17 million to total Company earnings before income tax for the six months ended June 30, 2014 compared to $28 million for the six months ended June 30, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.9		1.6		(0.7		)	(43.8	)%
Average Sales Price Per High Vol Met Ton Sold	$	58.19	$	65.96	$	(7.77	)	(11.8	)%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	26.73	$	32.55	$	(5.82	)	(17.9	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	3.05		1.39		1.66			119.4	%
Total Direct Services to Operations Per High Vol Met Ton Produced	3.94		6.12		(2.18		)	(35.6	)%
Total Retirement and Disability Per High Vol Met Ton Produced	2.97		3.16		(0.19		)	(6.0	)%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.57		6.13		(0.56		)	(9.1	)%
Total Production Costs Per High Vol Met Ton Produced	$	42.26	$	49.35	$	(7.09	)	(14.4	)%

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

Total Costs Per High Vol Met Ton Sold	$	42.26	$	49.35	$	(7.09	)	(14.4	)%
Margin Per High Vol Met Ton Sold	$	15.93	$	16.61	$	(0.68	)	(4.1	)%

High volatile metallurgical coal revenue was $49 million for the six months ended June 30, 2014 compared to $103 million for the six months ended June 30, 2013. The $54 million decrease was primarily due to the 0.7 million decrease in sales tons along with the $7.77 per ton decrease in average sales price. The decrease in sales price was due to 0.8 million tons of high volatile metallurgical coal being sold on the export market at an average sales price of $58.13 per ton for the six months ended June 30, 2014 compared to 1.3 million tons at an average price of $63.41 per ton for the six months ended June 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold for high volatile metallurgical coal was $35 million for the six months ended June 30, 2014, or $42 million lower than the $77 million for the six months ended June 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $42.26 per ton in the six months ended June 30, 2014 compared to $49.35 per ton in the six months ended June 30, 2013. The decrease in total dollars and unit costs was due to the lower tons sold in the period-to-period comparison.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $21 million to total Company earnings before income tax in the six months ended June 30, 2014 compared to $85 million in the six months ended June 30, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Six Months Ended June 30,
	2014		2013		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	2.0		2.6		(0.6		)	(23.1	)%
Average Sales Price Per Low Vol Met Ton Sold	$	74.13	$	100.41	$	(26.28	)	(26.2	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	65.68	$	86.38	$	(20.70	)	(24.0	)%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	39.50	$	40.96	$	(1.46	)	(3.6	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	4.50		5.79		(1.29		)	(22.3	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.12		4.77		0.35			7.3	%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.47		5.37		0.10			1.9	%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.97		8.18		0.79			9.7	%
Total Production Costs Per Low Vol Met Ton Produced	$	63.56	$	65.07	$	(1.51	)	(2.3	)%

Ending Inventory Costs Per Low Vol Met Ton	$	60.96	$	64.76	$	(3.80	)	(5.9	)%

Total Costs Per Low Vol Met Ton Sold	$	63.98	$	67.10	$	(3.12	)	(4.6	)%
Margin Per Low Vol Met Ton Sold	$	10.15	$	33.31	$	(23.16	)	(69.5	)%

Low volatile metallurgical coal revenue was $151 million for the six months ended June 30, 2014 compared to $258 million for the six months ended June 30, 2013. The $107 million decrease was attributable to a $26.28 per ton lower average sales price and a 0.6 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. CONSOL Energy priced 1.6 million tons of low volatile metallurgical coal in the export market at an average sales price of $65.84 per ton for the six months ended June 30, 2014 compared to 2.0 million tons at an average price of $89.53 per ton for the six months ended June 30, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold for low volatile metallurgical coal was $130 million for the six months ended June 30, 2014, or $43 million lower than the $173 million for the six months ended June 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $63.98 per ton in the six months ended June 30, 2014 compared to $67.10 per ton in the six months ended June 30, 2013. The decrease in total dollars and unit costs per low volatile metallurgical ton was primarily due to lower royalty and production taxes, lower wage and wage related expenses, and lower gas well plugging costs. The decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. These improvements were offset, in part, by lower tons sold.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $71 million for the six months ended June 30, 2014 compared to a loss before income tax of $89 million for the six months ended June 30, 2013. The other coal segment includes purchased coal activities and idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications and coal purchased from third parties and sold directly to our customers. The revenues were $7 million for the six months ended June 30, 2014 compared to $11 million for the six months ended June 30, 2013.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset by freight expense. Freight revenue was $20 million for the six months ended June 30, 2014 compared to $22 million for the six months ended June 30, 2013. The $2 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $79 million for the six months ended June 30, 2014 compared to $56 million for the six months ended June 30, 2013. The change is due to the following items:



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance
Coal Contract Buyout	$	30	$	—	$	30
Rental Income	25		2		23
Royalty Income	10		9		1
Equity in earnings of affiliates	7		10		(3		)
Business Interruption Proceeds - Bailey Mine	—		3		(3		)
Gain on Sale of Assets	—		26		(26		)
Other	7		6		1
Total Other Income Coal Segment	$	79	$	56	$	23


•	For the six months ended June 30, 2014, $30 million of income was related to a coal customer contract buyout. The discontinued contract was a long term contract that created pricing risks for both parties. The parties agreed to an amicable settlement and anticipate a continued relationship in the future. No such transactions were entered into in the six months ended June 30, 2013.


•	Rental income increased $23 million due to equipment subleased to a third-party. These arrangements began in December 2013.


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


•	Equity in earnings of affiliates decreased $3 million due to various transactions completed by our equity partners, none of which were individually material.


•	Business interruption proceeds of $3 million were received in the prior year-to-date period related to the 2012 Bailey Belt Conveyor accident.


•	Gain on sale of assets decreased $26 million primarily due to the sale of Potomac coal reserves in the six months ended June 30, 2013. No such transactions were entered into in the six months ended June 30, 2014.


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

Other coal segment total costs were $177 million for the six months ended June 30, 2014 compared to $178 million for the six months ended June 30, 2013. The decrease of $1 million was primarily due to the following items:



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance
Closed and Idle Mines	$	37	$	57	$	(20	)
Purchased Coal	11		21		(10		)
General and Administrative Expense	22		18		4
Stock-based and Incentive Compensation	31		32		(1		)
Freight Expense	20		22		(2		)
Lease Rental Expense	17		1		16
Depreciation, Depletion, and Amortization	14		13		1
Other	25		14		11
Total Other Coal Segment Costs	$	177	$	178	$	(1	)

•

Closed and idle mine costs decreased approximately $20 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. This was due to a $14 million decrease in the asset retirement obligation, primarily at the Fola Mining Complex. The remaining $6 million decrease was due to various changes in the operational status of other mines, between idled and operating throughout both periods, none of which were individually material.


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


•	General and Administrative Expense related to the other coal segment increased by $4 million primarily due to various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section entitled "Net Income (Loss) Attributable to CONSOL Energy Shareholders" of this quarterly report for detailed cost explanations.


•	Stock-based and Incentive Compensation decreased $1 million due to projected payout in both plans.

•

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


•	Lease rental expense increased $16 million primarily due to equipment leases that are subleased to a third-party. The third-party subleases began in December 2013.


•	Depreciation, Depletion, and Amortization increased $1 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.


•	Other expenses related to the Other Coal segment increased $11 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the six months ended June 30, 2014 compared to the six months ended June 30, 2013:

The other segment includes activity from the sales of industrial supplies, coal terminal activity and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $217 million for the six months ended June 30, 2014 compared to a loss before income tax of $165 million for the six months ended June 30, 2013. The other segment also includes total Company income tax expense of $10 million for the six months ended June 30, 2014 compared to an income tax expense of $29 million for the six months ended June 30, 2013.



	For the Six Months Ended June 30,
(in millions)	2014			2013			Variance			Percent Change
Sales—Outside	$	140		$	134		$	6		4.5	%
Other Income	5			5			—			—	%
Total Revenue	145			139			6			4.3	%
Cost of Goods Sold and Other Charges	174			197			(23		)	(11.7	)%
Depreciation, Depletion & Amortization	3			3			—			—	%
Loss on Debt Extinguishment	74			—			74			100.0	%
Interest Expense	111			104			7			6.7	%
Total Costs	362			304			58			19.1	%
Loss Before Income Tax	(217		)	(165		)	(52		)	31.5	%
Income Tax	10			29			(19		)	(65.5	)%
Net Loss	$	(227	)	$	(194	)	$	(33	)	17.0	%

Industrial supplies:

Outside Sales from industrial supplies were $119 million for the six months ended June 30, 2014 compared to $108 million for the six months ended June 30, 2013. The increase of $11 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $118 million for the six months ended June 30, 2014 compared to $106 million for the six months ended June 30, 2013. The increase of $12 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Coal terminal activity:

Outside Sales from terminal activity were $21 million for the six months ended June 30, 2014 compared to $26 million for the six months ended June 30, 2013. The decrease of $5 million was primarily attributable to decreased thru-put volumes for the current year.

Total costs related to terminal activity were $14 million for the six months ended June 30, 2014 compared to $16 million for the six months ended June 30, 2013. Costs decreased $2 million due to lower per ton thru-put costs and a decrease in thru-put volumes.

Miscellaneous other:

Additional other income of $5 million was recognized for the six months ended June 30, 2014 and June 30, 2013.

Other corporate costs were $230 million for the six months ended June 30, 2014 compared to $182 million for the six months ended June 30, 2013. Other corporate costs increased due to the following items:



	For the Six Months Ended June 30,
(in millions)	2014		2013		Variance
Loss On Debt Extinguishment	$	74	$	—	$	74
Interest Expense	111		104		7
Revolver Modification Fees	3		—		3
Bank Fees	8		7		1
Pension Settlement	21		32		(11		)
CNX Gas shareholder settlement	—		20		(20		)
Other	13		19		(6		)
	$	230	182		$	48


•	Loss on Debt Extinguishment of $74 million was recognized in the six 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 2017 at an average 1.04% premium. No such transactions occurred in the prior period.

•

Interest expense increased $7 million primarily due to less capitalized interest associated with the completion of the Bailey Mine, Enlow Fork Mine, and the Harvey Mine capital projects. The increase was offset, in part, by the IRS audit resolution causing a reduction to anticipated interest (See Note 6 - Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q), and lower bond and revolving credit facility interest.


•	Revolver modification fees resulted in a $3 million acceleration of previously deferred financing fees.


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

•

The CNX shareholder settlement was the result of an agreement for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the share of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provided for payment to the plaintiffs of $43 million, of which the Company's portion was $20 million.


•	Other corporate items decreased $6 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 9.1% for the six months ended June 30, 2014 compared to 85.6% for the six months ended June 30, 2013. The effective rates for the six months ended June 30, 2014 and 2013 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. 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 June 30,
(in millions)	2014			2013			Variance			Percent Change
Total Company Earnings Before Income Tax	$	106		$	34		$	72		214.9	%
Income Tax Expense (Benefit)	$	10		$	29		$	(19	)	(66.3	)%
Effective Income Tax Rate	9.1		%	85.6		%	(76.5		)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CONSOL Energy entered into a new Amended and Restated Credit Agreement dated June 18, 2014 for a $2.0 billion senior secured revolving credit facility which expires on June 18, 2019. The new senior revolving credit facility replaced CONSOL Energy's existing $1.0 billion senior secured revolving credit facility which had been entered into as of April 12, 2011 and amended and restated on December 5, 2013 and the existing $1.0 billion senior secured revolving credit facility of CNX Gas Corporation and it subsidiaries that had been entered into as of April 12, 2011. 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 generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan 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 4.15 to 1.00 at June 30, 2014. 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 minimum current ratio was 2.59 to 1.00 at June 30, 2014. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. 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, 2014, the facility had no outstanding borrowings and $260 million of letters of credit outstanding, leaving $1,740 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. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $125 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, 2014, eligible accounts receivable totaled approximately $86 million. At June 30, 2014, the facility had no outstanding borrowings and $62 million of letters of credit outstanding, leaving $24 million of unused capacity.

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

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap and option transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $9 million at June 30, 2014. The ineffective portion of these contracts was less than $1 million during the six months ended June 30, 2014. No issues related to our hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Six Months Ended June 30,
	2014			2013			Change
Cash flows from operating activities	$	557		$	393		$	164
Cash used in investing activities	$	(725	)	$	(465	)	$	(260	)
Cash used in financing activities	$	(12	)	$	122		$	(134	)

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


•	Net income increased $106 million in the period-to-period comparison.


•	Adjustments to reconcile net income to cash flow provided by operating activities increased $74 million due to the loss on extinguishment of debt, and additional depreciation, depletion and amortization of $46 million.


•	Income tax refunds of $72 million, net of payments, in the six months ended June 30, 2014 compared to $44 million of payments in the six months ended June 30, 2013.


•	These increases were offset, in part, by changes in discontinued operations.


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

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


•	Capital expenditures from continuing operations increased $112 million in the period-to-period comparison due to:


◦	Gas segment capital expenditures increased $175 million. The increase was comprised of increased drilling activity in the Marcellus and Utica plays and various other individually insignificant projects;

◦

Coal segment capital expenditures decreased $38 million. The decrease was comprised of $18 million related to the Enlow Fork Overland Belt Project, which was completed in February 2014 and an $80 million decrease in various other projects none of which were individually material. The decrease was partially offset by an increase of $60 million for the acquisition of the Harvey Mine longwall shields;


◦	Other capital expenditures decreased $25 million due to a decrease in capitalized interest of $12 million related to the completion of the Harvey Mine Capital project and $13 million related to various other miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Proceeds from the sale of assets, continuing operations, increased $25 million in the period-to-period comparison due to:


◦	$75 million received in March 2014 related to the Harvey Mine shield sale-leaseback;


◦	$46 million received in January 2014 as a reimbursement from Noble Energy for 50% of the Dominion Resources lease acquisition;


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


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

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


•	Net investments in equity affiliates increased $22 million due to $21 million in additional capital contributions to CONE in 2014 and $1 million in various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Restricted cash decreased $69 million due to the release of the cash restrictions including $48 million associated with the Ram River & Scurry Canadian asset proceeds and $21 million associated with the Ryerson Dam Settlement.


•	Discontinued Operations decreased $82 million due to no activity occurring in 2014 and proceeds for two long wall shield sale leasebacks in 2013.

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, 2014, CONSOL Energy repaid $3 million of miscellaneous borrowings. In the six months ended June 30, 2013, CONSOL Energy repaid $30 million of miscellaneous borrowings.


•	In the six months ended June 30, 2014, CONSOL Energy paid $12 million related to transaction fees in the refinancing of the revolving credit facilities. As compared to $173 million of short term borrowings received under the revolving credit facilities in the six months ended June 30, 2013.


•	In six months ended June 30, 2014, CONSOL Energy received $13 million due to the issuance of common stock as compared to $2 million received by the issuance of common stock in 2013.


•	In 2013, CONSOL Energy received $3 million of borrowings under its Securitization Facility, there was no activity in 2014.


•	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 Staments of this Form 10-Q for additional details.


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

The following is a summary of our significant contractual obligations at June 30, 2014 (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	$	76,010	$	174,367	$	153,611	$	7,319	$	411,307
Gas Firm Transportation	96,285		206,954		201,921		756,564		1,261,724
Long-Term Debt	3,535		6,657		2,941		3,205,315		3,218,448
Interest on Long-Term Debt	215,423		438,497		438,213		459,628		1,551,761
Capital (Finance) Lease Obligations	8,592		15,053		13,305		16,110		53,060
Interest on Capital (Finance) Lease Obligations	3,365		5,100		3,372		1,499		13,336
Operating Lease Obligations	104,553		186,882		152,968		50,884		495,287
Long-Term Liabilities—Employee Related (a)	88,901		183,443		187,449		787,662		1,247,455
Other Long-Term Liabilities (b)	272,057		177,040		83,180		360,551		892,828
Total Contractual Obligations (c)	$	868,721	$	1,393,993	$	1,236,960	$	5,645,532	$	9,145,206

_________________________


(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 payout table due to the uncertainty regarding amounts to be contributed. Estimated 2014 contributions are expected to be approximately $9 million.


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


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

Debt

At June 30, 2014, CONSOL Energy had total long-term debt and capital lease obligations of $3.27 billion outstanding, including the current portion of long-term debt of $12.1 million. This long-term debt consisted of:


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


•	An aggregate principal amount of $250 million of 6.375% 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 $1.6 billion of 5.875% notes due in April 2022. 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 $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 $11 million with an average interest rate of 7.93% per annum.


•	An aggregate principal amount of $4 million on other various rate notes maturing through June 2031.


•	An aggregate principal amount of $53 million of capital leases with a weighted average interest rate of 6.35% per annum.

At June 30, 2014, CONSOL Energy had no outstanding borrowings and had approximately $260 million of letters of credit outstanding under the $2.0 billion senior secured revolving credit facility.

At June 30, 2014, CONSOL Energy had no outstanding borrowings and had $62 million of letters of credit outstanding under the accounts receivable securitization facility.

Total Equity and Dividends

CONSOL Energy had total equity of $5.1 billion at June 30, 2014 and $5.0 billion at December 31, 2013. Total equity increased primarily due to net income in the current period, amortization of stock-based compensation and issuance of common stock. The increase in equity was offset, in part, by changes in comprehensive losses, dividends and treasury stock activity. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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



Declaration Date	Amount Per Share	Record Date	Payment Date
February 3, 2014	$0.0625	February 14, 2014	February 28, 2014
April 30, 2014	$0.0625	May 12, 2014	May 30, 2014
July 30, 2014	$0.0625	August 15, 2014	September 2, 2014

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 3.25 to 1.00 and the cumulative credit was approximately $350 million at June 30, 2014. The credit facility does not permit dividend payments in the event of default. The indentures to the 2020 and 2021 notes limit dividends to $0.40 per share annually unless several conditions are met. The indentures to the 2022 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 six months ended June 30, 2014.

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 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at June 30, 2014. 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, 2013 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, 2014. Management believes these items will expire without being funded. See Note 12 - Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Forward-Looking Statements

We are including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements (as defined in Section 21E of the 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 global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;


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


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


•	our reliance on major customers;


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


•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our 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;


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


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


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


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


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


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


•	the impacts of various asbestos litigation claims;


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


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


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


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


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


•	risks associated with our debt;


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


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


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


•	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; and


•	other factors discussed in this 2013 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

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

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CONSOL Energy's 2013 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at June 30, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $59.6 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $63.4 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2014, CONSOL Energy had $3.27 billion aggregate principal amount of debt outstanding under fixed-rate instruments and no amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings outstanding for the three months ended June 30, 2014.

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 June 17, 2014, 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
2014 Fixed Price Volumes
Hedged Mcf	N/A		N/A		41,740,578		41,740,578		83,481,156
Weighted Average Hedge Price per Mcf	N/A		N/A		$	4.58	$	4.58	$	4.58
2015 Fixed Price Volumes
Hedged Mcf	20,376,220		20,602,622		20,829,025		20,829,025		82,636,892
Weighted Average Hedge Price per Mcf	$	4.07	$	4.07	$	4.07	$	4.07	$	4.07
2016 Fixed Price Volumes
Hedged Mcf	18,711,058		18,711,058		18,916,674		18,916,674		75,255,464
Weighted Average Hedge Price per Mcf	$	4.17	$	4.17	$	4.17	$	4.17	$	4.17


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, 2014 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II: OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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, and Canada officially withdrew from its Kyoto commitment in 2012) 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 has elected to regulate GHGs under the Clean Air Act.

On June 2, 2014, the U.S. Environmental Protection Agency (EPA) announced its proposed “Clean Power Plan”, which would require states to impose various measures intended to reduce carbon dioxide (CO2) emissions from existing power plants under Section 111(d) of the Clean Air Act. The proposed rule requires each state to reduce its CO2 emission rate from existing fossil fuel plants beginning in 2020 to meet final state-specific rates by 2030. The EPA estimates that by 2030, the rule will achieve a 30% reduction in CO2 emissions from the U.S. electric power sector from 2005 levels. Under the proposed rule, which is expected to be finalized in 2015, states will have until June 2016 to submit initial state implementation plans, which would be finalized by June 2017, for stand-alone plans, and by June 2018, for multi-state plans. In its regulatory impact analysis, EPA forecasts that the proposed rule, when fully implemented in 2030, will reduce coal consumption for electricity generation by about 27% relative to the base case (i.e., relative to what it would be in the absence of the regulation), and will reduce mine-mouth coal prices by about 15% relative to the base case.

Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had 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.

Adoption of comprehensive legislation or regulation focusing on GHGs emission reductions for the United States (including the proposed rules discussed above) 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 addition, 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.

ITEM 4. MINE SAFETY DISCLOSURES

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


ITEM 6.	EXHIBITS



4.1			Indenture, dated as of April 16, 2014, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee, with respect to the 5.875% Senior Notes due 2022, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 16, 2014.

4.2			Registration Rights Agreement, dated as of April 16, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto and J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers named therein, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 16, 2014.

10.1			Amended and Restated Credit Agreement, dated as of June 18, 2014, by and among CONSOL Energy Inc., the lenders and agents party thereto 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 June 25, 2014 as amended by Form 8-K/A filed on June 25, 2014.

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, 2014 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: August 1, 2014



	CONSOL ENERGY INC.

	By:		/S/ NICHOLAS J. DEIULIIS
			Nicholas J. DeIuliis
			Chief Executive Officer and President (Duly Authorized Officer and Principal Executive Officer)

	By:		/S/ DAVID M. KHANI
			David M. Khani
			Chief Financial Officer and Executive Vice President (Duly Authorized Officer and Principal Financial Officer)

	By:		/S/ LORRAINE L. RITTER
			Lorraine L. Ritter
			Controller and Vice President (Duly Authorized Officer and Principal Accounting Officer)

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