CNX Resources Corp - Quarter Report: 2014 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended September 30, 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 October 17, 2014
Common stock, $0.01 par value		230,179,532

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and nine months ended September 30, 2014 and 2013.	3
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013.	4
	Consolidated Balance Sheets at September 30, 2014 and December 31, 2013.	5
	Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2014.	7
	Consolidated Statements of Cash Flows for the nine months ended September 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	42

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	91

ITEM 4.	Controls and Procedures	92

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	92

ITEM 4.	Mine Safety Disclosures	92

ITEM 6.	Exhibits	93

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.

Dth/d- Decatherms per day, with one decatherm being equivalent to one million British Thermal units.

PART I : FINANCIAL INFORMATION


ITEM 1.	CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



(Dollars in thousands, except per share data)	Three Months Ended						Nine Months Ended
(Unaudited)	September 30,						September 30,
Revenues and Other Income:	2014			2013			2014			2013
Natural Gas, NGLs and Oil Sales	$	257,358		$	192,781		$	753,399		$	531,859
Coal Sales	483,960			479,311			1,554,939			1,532,280
Other Outside Sales	73,673			63,876			213,047			197,778
Gas Royalty Interests and Purchased Gas Sales	18,815			17,113			68,773			51,109
Freight-Outside Coal	2,497			9,579			22,551			31,492
Miscellaneous Other Income	40,784			20,822			165,815			77,729
Gain on Sale of Assets	7,529			19,863			12,615			52,208
Total Revenue and Other Income	884,616			803,345			2,791,139			2,474,455
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	30,005			23,600			85,622			70,835
Transportation, Gathering and Compression	68,234			46,699			179,813			144,002
Production, Ad Valorem, and Other Fees	8,486			8,033			28,817			20,011
Direct Administrative and Selling	14,060			11,725			39,216			34,615
Depreciation, Depletion and Amortization	82,538			58,998			225,766			164,832
Exploration and Production Related Other Costs	8,042			22,771			15,765			43,666
Production Royalty Interests and Purchased Gas Costs	15,751			13,805			58,519			41,165
Other Corporate Expenses	13,700			26,289			60,876			74,239
General and Administrative	14,874			10,177			47,755			29,239
Total Exploration and Production Costs	255,690			222,097			742,149			622,604
Coal Costs
Operating and Other Costs	339,216			328,393			1,013,606			993,342
Royalties and Production Taxes	23,306			24,380			77,397			79,257
Direct Administrative and Selling	10,479			11,608			33,589			34,744
Depreciation, Depletion and Amortization	64,880			57,265			186,029			169,702
Freight Expense	2,497			9,579			22,551			31,492
General and Administrative Costs	10,434			8,607			33,397			27,946
Other Corporate Expenses	10,114			11,145			41,444			43,056
Total Coal Costs	460,926			450,977			1,408,013			1,379,539
Other Costs
Miscellaneous Operating Expense	92,974			75,439			266,601			272,346
General and Administrative Costs	425			376			1,259			1,269
Depreciation, Depletion and Amortization	1,247			1,467			3,885			4,303
Loss on Debt Extinguishment	20,990			—			95,267			—
Interest Expense	55,397			56,300			170,539			164,194
Total Other Costs	171,033			133,582			537,551			442,112
Total Costs And Expenses	887,649			806,656			2,687,713			2,444,255
(Loss) Earnings Before Income Tax	(3,033		)	(3,311		)	103,426			30,200
Income Taxes	(1,388		)	68,858			8,315			97,531
(Loss) Income From Continuing Operations	(1,645		)	(72,169		)	95,111			(67,331		)
Income (Loss) From Discontinued Operations, net	—			8,120			(5,687		)	(11,352		)
Net (Loss) Income	(1,645		)	(64,049		)	89,424			(78,683		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(398		)	—			(942		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(1,645	)	$	(63,651	)	$	89,424		$	(77,741	)

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(CONTINUED)



	Three Months Ended						Nine Months Ended
(Dollars in thousands, except per share data)	September 30,						September 30,
(Unaudited)	2014			2013			2014			2013
(Loss) Earnings Per Share
Basic
(Loss) Income from Continuing Operations	$	(0.01	)	$	(0.31	)	$	0.41		$	(0.29	)
Income (Loss) from Discontinued Operations	—			0.03			(0.02		)	(0.05		)
Total Basic (Loss) Earnings Per Share	$	(0.01	)	$	(0.28	)	$	0.39		$	(0.34	)
Dilutive
(Loss) Income from Continuing Operations	$	(0.01	)	$	(0.31	)	$	0.41		$	(0.29	)
Income (Loss) from Discontinued Operations	—			0.03			(0.02		)	(0.05		)
Total Dilutive (Loss) Earnings Per Share	$	(0.01	)	$	(0.28	)	$	0.39		$	(0.34	)

Dividends Paid Per Share	$	0.0625		$	0.125		$	0.1875		$	0.25

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended						Nine Months Ended
(Dollars in thousands)	September 30,						September 30,
(Unaudited)	2014			2013			2014			2013
Net (Loss) Income	$	(1,645	)	$	(64,049	)	$	89,424		$	(78,683	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($107,383), ($15,422), ($108,154), ($70,161))	184,154			24,980			185,475			113,641
Net Increase (Decrease) in the Value of Cash Flow Hedges (Net of tax: ($25,722), ($8,536), $13,161, ($26,036))	39,151			13,246			(20,032		)	40,400
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $12,084, $14,025, ($5,509), $36,551)	(19,510		)	(24,354		)	3,754			(56,595		)

Other Comprehensive Income	203,795			13,872			169,197			97,446

Comprehensive Income (Loss)	202,150			(50,177		)	258,621			18,763

Less: Comprehensive Loss Attributable to Noncontrolling Interest	—			(398		)	—			(942		)

Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	202,150		$	(49,779	)	$	258,621		$	19,705

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands)	September 30, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and Cash Equivalents	$	225,563	$	327,420
Accounts and Notes Receivable:
Trade	299,939		332,574
Notes Receivable	—		25,861
Other Receivables	382,652		243,973
Inventories	145,372		157,914
Deferred Income Taxes	127,731		211,303
Recoverable Income Taxes	41,971		10,705
Prepaid Expenses	101,867		135,842
Total Current Assets	1,325,095		1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	14,463,328		13,578,509
Less—Accumulated Depreciation, Depletion and Amortization	4,499,344		4,136,247
Total Property, Plant and Equipment—Net	9,963,984		9,442,262
Other Assets:
Investment in Affiliates	185,509		291,675
Notes Receivable	—		125
Other	244,347		214,013
Total Other Assets	429,856		505,813
TOTAL ASSETS	$	11,718,935	$	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)	September 30, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	610,725		$	514,580
Current Portion of Long-Term Debt	12,225			11,455
Other Accrued Liabilities	610,704			565,697
Current Liabilities of Discontinued Operations	12,992			28,239
Total Current Liabilities	1,246,646			1,119,971
Long-Term Debt:
Long-Term Debt	3,236,172			3,115,963
Capital Lease Obligations	43,150			47,596
Total Long-Term Debt	3,279,322			3,163,559
Deferred Credits and Other Liabilities:
Deferred Income Taxes	395,025			242,643
Postretirement Benefits Other Than Pensions	652,050			961,127
Pneumoconiosis Benefits	111,514			111,971
Mine Closing	321,776			320,723
Gas Well Closing	180,520			175,603
Workers’ Compensation	73,398			71,468
Salary Retirement	48,231			48,252
Reclamation	34,499			40,706
Other	121,355			131,355
Total Deferred Credits and Other Liabilities	1,938,368			2,103,848
TOTAL LIABILITIES	6,464,336			6,387,378
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 230,177,923 Issued and Outstanding at September 30, 2014; 229,145,736 Issued and Outstanding at December 31, 2013	2,305			2,294
Capital in Excess of Par Value	2,412,976			2,364,592
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,995,238			2,964,520
Accumulated Other Comprehensive Loss	(155,920		)	(325,117		)
Total CONSOL Energy Inc. Stockholders’ Equity	5,254,599			5,006,289
TOTAL LIABILITIES AND EQUITY	$	11,718,935		$	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 (Loss) Income			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	—		—		89,424			—			89,424
Other Comprehensive Income	—		—		—			169,197			169,197
Comprehensive Income	—		—		89,424			169,197			258,621
Issuance of Common Stock	11		13,392		—			—			13,403
Treasury Stock Activity	—		—		(15,587		)	—			(15,587		)
Tax Benefit From Stock-Based Compensation	—		2,478		—			—			2,478
Amortization of Stock-Based Compensation Awards	—		32,514		—			—			32,514
Dividends ($0.1875 per share)	—		—		(43,119		)	—			(43,119		)
September 30, 2014	$	2,305	$	2,412,976	$	2,995,238		$	(155,920	)	$	5,254,599

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



(Dollars in thousands)	Nine Months Ended
(Unaudited)	September 30,
Operating Activities:	2014			2013
Net Income (Loss)	$	89,424		$	(78,683	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Continuing Operating Activities:
Net Loss from Discontinued Operations	5,687			11,352
Depreciation, Depletion and Amortization	415,680			338,837
Stock-Based Compensation	32,514			44,026
Gain on Sale of Assets	(12,615		)	(52,208		)
Loss on Debt Extinguishment	95,267			—
Deferred Income Taxes	6,540			(23,335		)
Equity in Earnings of Affiliates	(38,477		)	(20,276		)
Return on Equity Investments	47,424			—
Changes in Operating Assets:
Accounts and Notes Receivable	(64,241		)	11,145
Inventories	12,542			11,000
Prepaid Expenses	3,178			(8,688		)
Changes in Other Assets	(14,339		)	24,318
Changes in Operating Liabilities:
Accounts Payable	151,829			(18,487		)
Accrued Interest	32,698			50,184
Other Operating Liabilities	116,474			122,429
Other	(8,480		)	39,356
Net Cash Provided by Continuing Operations	871,105			450,970
Net Cash (Used in) Provided by Discontinued Operating Activities	(20,934		)	138,029
Net Cash Provided by Operating Activities	850,171			588,999
Cash Flows from Investing Activities:
Capital Expenditures	(1,174,607		)	(1,021,127		)
Change in Restricted Cash	—			56,410
Proceeds from Sales of Assets	141,136			464,638
Net Investments In Equity Affiliates	108,532			(18,112		)
Net Cash Used in Investing Activities in Continuing Operations	(924,939		)	(518,191		)
Net Cash Used in Investing Activities in Discontinued Operations	—			(41,246		)
Net Cash Used in Investing Activities	(924,939		)	(559,437		)
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	(11,736		)	47,000
Payments on Miscellaneous Borrowings	(4,169		)	(31,858		)
Proceeds from Long-Term Borrowings	1,859,920			—
Payments on Long-Term Borrowings	(1,843,866		)	—
Proceeds from Securitization Facility	—			6,518
Tax Benefit from Stock-Based Compensation	2,478			2,316
Dividends Paid	(43,119		)	(57,211		)
Issuance of Common Stock	13,403			2,698
Treasury Stock Activity	—			609
Net Cash Used in Financing Activities in Continuing Operations	(27,089		)	(29,928		)
Net Cash Used in Financing Activities in Discontinued Operations	—			(432		)
Net Cash Used in Financing Activities	(27,089		)	(30,360		)
Net Decrease in Cash and Cash Equivalents	(101,857		)	(798		)
Cash and Cash Equivalents at Beginning of Period	327,420			21,862
Cash and Cash Equivalents at End of Period	$	225,563		$	21,064

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 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 September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
Anti-Dilutive Options	4,116,136	4,833,174	359,488	4,833,174
Anti-Dilutive Restricted Stock Units	1,278,078	1,243,207	—	1,243,207
Anti-Dilutive Performance Share Units	287,226	97,142	—	97,142
Anti-Dilutive Performance Share Options	802,804	602,101	—	602,101
	6,484,244	6,775,624	359,488	6,775,624

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
Options	7,456	11,655	655,568	256,768
Restricted Stock Units	6,034	130,523	396,836	698,664
Performance Share Units	—	—	378,971	159,228
	13,490	142,178	1,431,375	1,114,660

The weighted average exercise price per share of the options exercised during the three months ended September 30, 2014 and 2013 was $22.75 and $17.40, respectively. The weighted average exercise price per share of the options exercised during the nine months ended September 30, 2014 and 2013 was $20.44 and $10.49, respectively.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
(Loss) Income from Continuing Operations	$	(1,645	)	$	(72,169	)	$	95,111		$	(67,331	)
Income (Loss) from Discontinued Operations	—			8,120			(5,687		)	(11,352		)
Less: Net Loss Attributable to Noncontrolling Interest	—			(398		)	—			(942		)
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(1,645	)	$	(63,651	)	$	89,424		$	(77,741	)
Weighted average shares of common stock outstanding:
Basic	230,174,256			228,876,336			229,922,936			228,640,671
Effect of stock-based compensation awards	—			—			1,479,976			—
Dilutive	230,174,256			228,876,336			231,402,912			228,640,671
Earnings per share:
Basic (Continuing Operations)	$	(0.01	)	$	(0.31	)	$	0.41		$	(0.29	)
Basic (Discontinued Operations)	—			0.03			(0.02		)	(0.05		)
Total Basic	$	(0.01	)	$	(0.28	)	$	0.39		$	(0.34	)

Dilutive (Continuing Operations)	$	(0.01	)	$	(0.31	)	$	0.41		$	(0.29	)
Dilutive (Discontinued Operations)	—			0.03			(0.02		)	(0.05		)
Total Dilutive	$	(0.01	)	$	(0.28	)	$	0.39		$	(0.34	)

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 (loss) income before reclassifications	(20,032		)	176,385			156,353
Amounts reclassified from accumulated other comprehensive income	3,754			9,090			12,844
Current period other comprehensive (loss) income	(16,278		)	185,475			169,197
Balance at September 30, 2014	$	26,215		$	(182,135	)	$	(155,920	)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Derivative Instruments (Note 13)
Natural gas price swaps and options	$	(31,594	)	$	(38,379	)	$	9,263		$	(93,146	)
Tax benefit (expense)	12,084			14,025			(5,509		)	36,551
Net of tax	$	(19,510	)	$	(24,354	)	$	3,754		$	(56,595	)
Actuarially Determined Long-Term Liability Adjustments*(Note 4 and Note 5)
Amortization of prior service costs	$	(2,542	)	$	(8,212	)	$	(7,625	)	$	(24,635	)
Recognized net actuarial loss	11,198			21,055			32,705			69,802
Curtailment gains	(36,182		)	—			(36,182		)	—
Settlement loss	4,785			6,296			25,492			38,498
Total	(22,741		)	19,139			14,390			83,665
Tax benefit (expense)	8,376			(7,306		)	(5,300		)	(31,936		)
Net of tax	$	(14,365	)	$	11,833		$	9,090		$	51,729

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In March 2014, CONSOL Energy completed a sale-leaseback of longwall shields for the Harvey Mine. Cash proceeds from 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 nine months ended September 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 in 2014. Cash proceeds received from Noble Energy were $46,311 in the nine months ended September 30, 2014.

In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24,764. A gain of $15,260 was included in Other Income in the Consolidated Statement of Income.

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

In 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 provided 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 provided 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 has been approved but with special conditions that will need further approval.

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 has an obligation to 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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Equity in Earnings of Affiliates	$	18,284	$	3,610	$	39,796	$	20,276
Rental Income	9,731		770		35,336		2,654
Coal Contract Settlement	—		—		30,000		—
Gathering Revenue	3,636		766		24,386		5,863
Royalty Income	5,003		4,113		14,758		12,870
Right of Way Issuance	2,485		2,102		4,898		3,810
Bailey Belt Settlement	—		—		4,275		—
Interest Income	527		4,300		1,827		15,701
Business Interruption Insurance	—		2,745		—		5,445
Other	1,118		2,416		10,539		11,110
Total Other Income	$	40,784	$	20,822	$	165,815	$	77,729

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 nine months ended September 30 are as follows:



	Pension Benefits												Other Post-Employment Benefits
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	4,834		$	4,897		$	13,625		$	16,184		$	2,331		$	4,849		$	6,994		$	14,547
Interest cost	8,667			9,497			26,812			27,249			12,096			29,619			36,290			88,856
Expected return on plan assets	(12,829		)	(13,336		)	(38,342		)	(38,191		)	—			—			—			—
Amortization of prior service credits	(346		)	(408		)	(1,038		)	(1,223		)	(2,196		)	(7,804		)	(6,588		)	(23,411		)
Recognized net actuarial loss	6,444			8,042			18,441			30,764			6,369			17,595			19,106			52,784
Settlement loss	4,785			6,296			25,492			38,498			—			—			—			—
Curtailment gain	(549		)	—			(549		)	—			(35,633		)	—			(35,633		)	—
Net periodic cost (benefit)	$	11,006		$	14,988		$	44,441		$	73,281		$	(17,033	)	$	44,259		$	20,169		$	132,776

Expenses attributable to discontinued operations included in net periodic cost above were $1,699 and $7,078 for the three and nine months ended September 30, 2013, respectively, for the Pension Plans; and were $25,775 and $76,673 for the three and nine months ended September 30, 2013, respectively, for the Other Post-Employment Benefit Plan.

For the nine months ended September 30, 2014, $25,948 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 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.

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

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three and nine months ended September 30, 2014. Accordingly, CONSOL Energy recognized settlement expense of $4,785 and $25,492 for the three and nine months ended September 30, 2014 in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement accounting was initially triggered in May 2014, resulting in a remeasurement at May 31. Additional lump sum distributions during June and September 2014 resulted in remeasurements at June 30, 2014 and September 30, 2014. The September 30, 2014 remeasurement used a discount rate of 4.33%, an increase from 4.26% used at June 30, 2014. The September remeasurement increased the pension liability by $13,152. The September settlement and corresponding remeasurement of the pension plan resulted in a decrease of $5,285 in Other Comprehensive Income, net of $3,082 in deferred taxes. The May 31 and June 30, 2014 remeasurements used a discount rate of 4.26%, a decrease from 4.87% used at December 31, 2013. The May remeasurement increased the pension liability by $41,527. The May settlement and corresponding remeasurement of the pension plan resulted in a decrease of $14,193 in Other Comprehensive Income, net of $8,276 in deferred taxes. The June remeasurement decreased the pension liability by $6,490. The June settlement and corresponding remeasurement of the pension plan resulted in an increase of $5,141 in Other Comprehensive Income, net of $2,998 in deferred taxes. If CONSOL Energy incurs additional lump sum distributions from the plan in the fourth quarter of 2014, additional settlement charges will be recorded.

Lump sum payments also exceeded the settlement threshold during the three and nine months ended September 30, 2013. Accordingly, CONSOL Energy recognized settlement expense of $6,296 and $38,498 for the three and nine months ended September 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 September 30, June 30 and March 31, 2013. The September 30, 2013 remeasurement resulted in a change to the discount rate to 4.80% from 4.84% at June 30, 2013. The September remeasurement reduced the pension liability by $21,264. The September settlement and corresponding remeasurement of the pension plan resulted in an increase of $17,040 in Other Comprehensive Income, net of $10,520 in deferred taxes. 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.

On September 30, 2014, the salaried OPEB plan and Production and Maintenance (P&M) OPEB plan were remeasured to reflect an announced plan amendment that will reduce retiree medical and life insurance benefits as of September 30, 2014. Effective September 30, 2014, no retiree medical or life benefits will be provided to active employees. Retirees as of September 30, 2014 will continue in the OPEB plans, which are currently anticipated to remain unchanged through December 31, 2019, and coverage thereafter will be eliminated. The Company elected to make cash transition payments totaling approximately $46,282 to the active employees whose retiree medical and life benefits were eliminated by the changes to the OPEB plan. These cash payments are not considered to be post-retirement benefits, and as such, they are not included in the actuarial calculations related to the OPEB plans. The amendment to the OPEB plan resulted in a $315,439 reduction in the OPEB liability with a corresponding adjustment of $199,252 in Other Comprehensive Income, net of $116,187 in deferred taxes. A

curtailment gain of $35,633 was recognized in September 2014 with a corresponding adjustment of $22,508 in Other Comprehensive Income, net of $13,125 in deferred taxes. The amendment resulted in a remeasurement of the OPEB plan at September 30, 2014. The remeasurement resulted in a change to the discount rate to 1.92% for the P&M OPEB plan and 1.84% for the Salaried OPEB plan from 4.88% used at December 31, 2013. The remeasurement increased the OPEB liability by $9,634 with a corresponding decrease of $6,086 in Other Comprehensive Income, net of $3,548 in deferred taxes. The change was made to align our compensation package more closely with our peer group.

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 nine months ended September 30, 2014, $46,272 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 nine months ended September 30 are as follows:



	CWP												Workers' Compensation
	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	1,419		$	2,135		$	4,255		$	6,405		$	2,446		$	3,533		$	7,336		$	10,599
Interest cost	1,384			1,808			4,153			5,424			894			1,655			2,683			4,966
Amortization of actuarial gain	(1,549		)	(4,213		)	(4,647		)	(12,638		)	(96		)	(699		)	(287		)	(2,098		)
State administrative fees and insurance bond premiums	—			—			—			—			999			1,496			3,039			4,500
Legal and administrative costs	—			—			—			—			—			591			—			1,773
Net periodic cost (benefit)	$	1,254		$	(270	)	$	3,761		$	(809	)	$	4,243		$	6,576		$	12,771		$	19,740

Expenses (income) attributable to discontinued operations included in the net periodic cost (benefit) above were ($167) and ($497) for the three and nine months ended September 30, 2013, respectively, for CWP; and were $2,474 and $7,327 for the three and nine months ended September 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 nine months ended September 30, 2014, $8,870 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 nine months ended September 30, 2014, $11,327 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 nine months ended September 30, 2014 and 2013 was 8.3% and 323.0%, respectively.

The effective tax rate for the nine months ended September 30, 2014 differs from the U.S. federal statutory rate of 35% primarily due to a $20,640 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 $7,013 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 nine months ended September 30, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. The tax benefit of $7,970 related to increased percentage depletion deductions offset by $957 of tax expense related to changes in the Domestic Production Activities Deduction and changes in various other estimates.

The rate for the nine months ended September 30, 2013 differs from the U.S. federal statutory rate of 35% primarily due to a $111,104 income tax benefit for excess depletion, $4,701 discrete income tax charge related to the gain on sale of the Potomac coal reserves, $8,467 discrete income tax charge related to the gain on sale of the Crowsnest Pass coal reserves, a $1,585 income tax benefit due to a refund claim related to prior year Commonwealth of Pennsylvania taxes, and a $5,875 discrete income tax charge as a result of changes in estimates of excess percentage depletion and Domestic Production Activities Deduction related to the prior-year tax provision.

The total amounts of uncertain tax positions at September 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 nine months ended September 30, 2014. 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 September 30, 2014 and December 31, 2013, the Company reported an accrued interest liability relating to uncertain tax positions of $1,334 and $6,200, respectively. The accrued interest liability includes $4,866 of interest income and $1,020 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the nine months ended September 30, 2014 and 2013, respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of September 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 nine months ended September 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 Energy was required to file amended state income tax returns for the changes. In the nine months ended September 30, 2014, the Company filed the required amended returns and realized a discrete state income tax charge of $5,496 which was offset by a federal income tax benefit of $1,924.

NOTE 7—INVENTORIES:

Inventory components consist of the following:



	September 30, 2014		December 31, 2013
Coal	$	24,380	$	31,944
Merchandise for resale	35,836		38,263
Supplies	85,156		87,707
Total Inventories	$	145,372	$	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 $19,835 and $18,836 at September 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 September 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 $692 and $1,328 for the nine months ended September 30, 2014 and 2013, respectively. These costs have been recorded as financing fees which are included 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 September 30, 2014 and December 31, 2013, eligible accounts receivable totaled $82,500 and $115,000, respectively. There was $20,570 subordinated retained interest at September 30, 2014 and $48,945 subordinated retained interest at December 31, 2013. There were no borrowings under the Securitization Facility as of September 30, 2014 and December 31, 2013. The accounts receivable securitization program had no change in the nine months ended September 30, 2014. 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:



	September 30, 2014		December 31, 2013
Coal and Other Plant and Equipment	$	3,731,618	$	3,681,051
Intangible Drilling Cost	2,388,790		1,937,336
Proven Gas Properties	1,684,675		1,670,404
Unproven Gas Properties	1,510,307		1,463,406
Coal Properties and Surface Lands	1,411,574		1,409,408
Gas Gathering Equipment	1,082,355		1,058,008
Gas Wells and Related Equipment	850,771		688,548
Airshafts	453,689		397,466
Mine Development	416,733		354,607
Coal Advance Mining Royalties	397,015		381,348
Leased Coal Lands	388,033		388,020
Other Gas Assets	125,484		126,239
Gas Advance Royalties	22,284		22,668
Total Property Plant and Equipment	14,463,328		13,578,509
Less: Accumulated Depreciation, Depletion, and Amortization	4,499,344		4,136,247
Total Net Property, Plant, and Equipment	$	9,963,984	$	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 September 30, 2014, Hess’ remaining carry obligation is $132,736.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 703 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. The carry has been in effect since 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 September 30, 2014, Noble Energy’s remaining carry obligation is $1,728,520.

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 secured 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 was amended and restated on December 5, 2013, and the existing $1,000,000 senior secured revolving credit facility of CNX Gas Corporation (CNX Gas) 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 nine months ended September 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 5.26 to 1.00 at

September 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 2.33 to 1.00 at September 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 September 30, 2014, the $2,000,000 facility had no borrowings outstanding and $264,544 of letters of credit outstanding, leaving $1,735,456 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:



	September 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	1,014,800			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%	1,850,000			—
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865			102,865
Senior notes due April 2022 at 5.875%, Premium	6,875			—
Senior notes due April 2022 at 5.875%, Amortization of Bond Premium	(148		)	—
Advance royalty commitments (7.93% weighted average interest rate for September 30, 2014 and December 31, 2013)	11,182			11,182
Other long-term notes maturing at various dates through 2031 (total value of $4,892 and $5,923 less unamortized discount of $736 and $1,050 at September 30, 2014 and December 31, 2013, respectively).	4,156			4,873
	3,239,730			3,118,920
Less amounts due in one year *	3,558			2,957
Long-Term Debt	$	3,236,172		$	3,115,963

* Excludes current portion of Capital Lease Obligations of $8,667 and $8,498 at September 30, 2014 and December 31, 2013, respectively.

Accrued interest related to Long-Term Debt of $93,709 and $63,272 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at September 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.

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

NOTE 12—COMMITMENTS AND CONTINGENT LIABILITIES:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. It is possible that the aggregate loss in the future with respect to these lawsuits and

claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amounts cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $388,156.

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 putative class consists of forced-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM, and Plaintiffs also allege CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, 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 plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Court of Appeals for the Fourth Circuit. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, 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 hearing on the CNX Gas Company motion to dismiss will be held in the next few weeks. Mediation efforts have been unsuccessful. 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 September 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	$	151,302	$	71,915	$	79,387	$	—	$	—
Environmental	39,363		37,635		1,728		—		—
Other	135,809		56,209		79,600		—		—
Total Letters of Credit	326,474		165,759		160,715		—		—
Surety Bonds:
Employee-Related	204,884		204,884		—		—		—
Environmental	661,191		619,041		42,150		—		—
Other	25,685		25,625		59		—		1
Total Surety Bonds	891,760		849,550		42,209		—		1
Guarantees:
Coal	183,700		125,250		58,450		—		—
Other	63,131		34,974		9,010		8,446		10,701
Total Guarantees	246,831		160,224		67,460		8,446		10,701
Total Commitments	$	1,465,065	$	1,175,533	$	270,384	$	8,446	$	10,702

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 September 30, 2014, the fair value of these guarantees was $3,000 and was included in Accounts Payable 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 September 30, 2014, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	240,865
1 - 3 years	371,127
3 - 5 years	224,394
More than 5 years	492,825
Total Purchase Obligations	$	1,329,211

Costs related to these purchase obligations include:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Major Equipment Purchases	$	9,255	$	6,682	$	99,416	$	15,481
Firm Transportation and Processing Expense	27,476		24,449		76,839		67,269
Gas Drilling Obligations	32,901		26,296		85,364		81,419
Total Costs Related to Purchase Obligations	$	69,632	$	57,427	$	261,619	$	164,169

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 liability 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 September 30, 2014, the total notional amount of the Company’s outstanding derivative instruments was 199.6 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, $14,853 of unrealized gain 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 September 30, 2014 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $51,710 and a liability of $8,554. The total asset is comprised of $31,520 and $20,190 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is

comprised of $7,204 and $1,350 which was 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 was 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 was as follows:



	For the Three Months Ended September 30,
	2014		2013
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	6,574	$	71,674
Gain recognized in Accumulated OCI	39,151		13,246
Less: Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales	19,510		24,354
Ending Balance – Accumulated OCI	$	26,215	$	60,566
Gain recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness	$	1,850	$	2,592



	For the Nine Months Ended September 30,
	2014			2013
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	42,493		$	76,761
(Loss)/Gain recognized in Accumulated OCI	(20,032		)	40,400
Less: (Loss)/Gain reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales	(3,754		)	56,595
Ending Balance – Accumulated OCI	$	26,215		$	60,566
Gain/(Loss) recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness	$	2,713		$	(120	)

There were no amounts excluded from the assessment of hedge effectiveness in the nine months ended September 30, 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 September 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	$	—	$	43,156	$	—	$	—	$	65,449	$	—
Murray Energy Guarantees	$	—	$	—	$	3,000	$	—	$	—	$	3,000

*- The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves.

**- The fair value of the assets and liabilities included in Level 3 are based on unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. The significant unobservable inputs used in the fair value measurement of our third party guarantees are the credit risk of the third party and the third party surety bond markets. A significant increase or decrease in the these values, in isolation, would have a directionally similar effect resulting in higher or lower fair value measurement of our Level 3 guarantees.

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:



	September 30, 2014						December 31, 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	225,563		$	225,563		$	327,420		$	327,420
Long-Term Debt	$	(3,239,730	)	$	(3,269,768	)	$	(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 and nine months ended September 30, 2014, the Thermal aggregated segment includes the following mines: Bailey Complex, Buchanan Mine, Enlow Fork Mine, Harvey Mine and Miller Creek Complex. For the three and nine months ended September 30, 2014, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the three and nine months ended September 30, 2014, the High Volatile Metallurgical aggregated segment includes: Bailey Complex, Enlow Fork Mine, 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 division. 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 September 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	$	109,850	$	82,913	$	25,377		$	39,218		$	257,358	$	398,863	$	69,850	$	14,684	$	563		$	483,960	$	73,673	$	—		$	814,991		(A)
Sales—purchased gas	—		—		—			1,205			1,205		—		—		—		—			—		—		—			1,205
Sales—gas royalty interests	—		—		—			17,610			17,610		—		—		—		—			—		—		—			17,610
Freight—outside	—		—		—			—			—		—		—		—		2,497			2,497		—		—			2,497
Intersegment transfers	—		485		—			—			485		—		—		—		—			—		23,066		(23,551		)	—
Total Sales and Freight	$	109,850	$	83,398	$	25,377		$	58,033		$	276,658	$	398,863	$	69,850	$	14,684	$	3,060		$	486,457	$	96,739	$	(23,551	)	$	836,303
Earnings (Loss) Before Income Taxes	$	27,328	$	19,790	$	(9,341	)	$	(92	)	$	37,685	$	81,660	$	9,115	$	8,056	$	(46,484	)	$	52,347	$	2,689	$	(95,754	)	$	(3,033	)	(B)
Segment assets											$	6,901,696										$	4,119,591	$	295,279	$	402,369		$	11,718,935		(C)
Depreciation, depletion and amortization											$	82,538										$	64,880	$	1,247	$	—		$	148,665
Capital expenditures											$	281,641										$	72,496	$	1,175	$	—		$	355,312

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

(B) Includes equity in earnings of unconsolidated affiliates of $9,991, $6,842 and $132 for E&P, Coal and All Other, respectively.

(C) Includes investments in unconsolidated equity affiliates of $92,188, $25,844 and $67,477 for E&P, Coal and All Other, respectively.

Industry segment results for the three months ended September 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	$	72,406	$	83,269	$	32,957		$	4,149		$	192,781		$	352,362	$	98,232	$	22,290	$	6,427		$	479,311	$	63,876		$	—		$	735,968		(D)
Sales—purchased gas	—		—		—			1,607			1,607			—		—		—		—			—		—			—			1,607
Sales—gas royalty interests	—		—		—			15,506			15,506			—		—		—		—			—		—			—			15,506
Freight—outside	—		—		—			—			—			—		—		—		9,579			9,579		—			—			9,579
Intersegment transfers	—		601		—			—			601			—		—		—		—			—		32,213			(32,814		)	—
Total Sales and Freight	$	72,406	$	83,870	$	32,957		$	21,262		$	210,495		$	352,362	$	98,232	$	22,290	$	16,006		$	488,890	$	96,089		$	(32,814	)	$	762,660
Earnings (Loss) Before Income Taxes	$	27,963	$	20,908	$	(2,123	)	$	(48,615	)	$	(1,867	)	$	95,916	$	21,297	$	4,801	$	(57,625	)	$	64,389	$	(2,385	)	$	(63,448	)	$	(3,311	)	(E)
Segment assets											$	5,994,072											$	4,118,351	$	356,731		$	2,267,918		$	12,737,072		(F)
Depreciation, depletion and amortization											$	58,998											$	57,265	$	1,467		$	—		$	117,730
Capital expenditures											$	273,474											$	32,497	$	7,704		$	—		$	313,675


(D)	There were no sales to customers aggregating over 10% of total revenue in the three months ending September 30, 2013.


(E)	Includes equity in earnings of unconsolidated affiliates of $5,307, $(1,769) and $72 for E&P, Coal and All Other, respectively.

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

Industry segment results for the nine months ended September 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	$	339,391	$	259,665	$	84,278		$	70,065		$	753,399	$	1,262,248	$	221,162	$	64,099	$	7,430		$	1,554,939	$	213,047	$	—		$	2,521,385	(G)
Sales—purchased gas	—		—		—			6,183			6,183		—		—		—		—			—		—		—			6,183
Sales—gas royalty interests	—		—		—			62,590			62,590		—		—		—		—			—		—		—			62,590
Freight—outside	—		—		—			—			—		—		—		—		22,551			22,551		—		—			22,551
Intersegment transfers	—		1,937		—			—			1,937		—		—		—		—			—		62,412		(64,349		)	—
Total Sales and Freight	$	339,391	$	261,602	$	84,278		$	138,838		$	824,109	$	1,262,248	$	221,162	$	64,099	$	29,981		$	1,577,490	$	275,459	$	(64,349	)	$	2,612,709
Earnings (Loss) Before Income Taxes	$	121,197	$	71,358	$	(16,194	)	$	(37,757	)	$	138,604	$	342,133	$	29,837	$	24,731	$	(117,588	)	$	279,113	$	5,941	$	(320,232	)	$	103,426	(H)
Segment assets											$	6,901,696										$	4,119,591	$	295,279	$	402,369		$	11,718,935	(I)
Depreciation, depletion and amortization											$	225,766										$	186,029	$	3,885	$	—		$	415,680
Capital expenditures											$	852,097										$	320,196	$	2,314	$	—		$	1,174,607


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


(H)	Includes equity in earnings of unconsolidated affiliates of $22,801, $16,635 and $(959) for E&P, Coal and All Other, respectively.

(I) Includes investments in unconsolidated equity affiliates of $92,188, $25,844 and $67,477 for E&P, Coal and All Other, respectively.

Industry segment results for the nine months ended September 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	$	167,394	$	254,708	$	99,138		$	10,619		$	531,859		$	1,034,228	$	356,066	$	124,957	$	17,029		$	1,532,280	$	197,778	$	—		$	2,261,917	(J)
Sales—purchased gas	—		—		—			4,372			4,372			—		—		—		—			—		—		—			4,372
Sales—gas royalty interests	—		—		—			46,737			46,737			—		—		—		—			—		—		—			46,737
Freight—outside	—		—		—			—			—			—		—		—		31,492			31,492		—		—			31,492
Intersegment transfers	—		2,363		—			—			2,363			—		—		—		—			—		100,118		(102,481		)	—
Total Sales and Freight	$	167,394	$	257,071	$	99,138		$	61,728		$	585,331		$	1,034,228	$	356,066	$	124,957	$	48,521		$	1,563,772	$	297,896	$	(102,481	)	$	2,344,518
Earnings (Loss) Before Income Taxes	$	53,411	$	64,213	$	(11,752	)	$	(112,989	)	$	(7,117	)	$	277,289	$	106,832	$	32,307	$	(146,597	)	$	269,831	$	5,076	$	(237,590	)	$	30,200	(K)
Segment assets											$	5,994,072											$	4,118,351	$	356,731	$	2,267,918		$	12,737,072	(L)
Depreciation, depletion and amortization											$	164,832											$	169,702	$	4,303	$	—		$	338,837
Capital expenditures											$	669,067											$	336,845	$	15,215	$	—		$	1,021,127


(J)	Included in the Coal segment are sales of $492,872 and $441,528 to First Energy and Xcoal Energy & Resources, respectively, which comprises over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $9,519, $10,525 and $232 for E&P, Coal and All Other, respectively.

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

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Earnings Before Income Taxes for total reportable business segments	$	90,032		$	62,522		$	417,717		$	262,714
Segment Earnings Before Income Taxes for all other businesses	2,689			(2,385		)	5,941			5,076
Interest expense, net and other non-operating activity (M)	(79,366		)	(57,479		)	(277,322		)	(166,542		)
Other Corporate Items (M)	(16,388		)	(5,969		)	(42,910		)	(71,048		)
Earnings Before Income Taxes	$	(3,033	)	$	(3,311	)	$	103,426		$	30,200



Total Assets:	September 30,
Total Assets:	2014		2013
Segment assets for total reportable business segments	$	11,021,287	$	10,112,423
Segment assets for all other businesses	295,279		356,731
Items excluded from segment assets:
Cash and other investments (M)	193,325		17,966
Recoverable income taxes	41,971		—
Deferred tax assets	127,731		25,585
Bond issuance costs	39,342		36,266
Discontinued Operations	—		2,188,101
Total Consolidated Assets	$	11,718,935	$	12,737,072

_________________________

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,014,800, 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 $1,850,000, 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 September 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	$	—		$	257,844	$	—	$	—	$	(486	)	$	257,358
Coal Sales	—			—		483,960		—		—			483,960
Other Outside Sales	—			—		8,175		65,498		—			73,673
Gas Royalty Interests and Purchased Gas Sales	—			18,815		—		—		—			18,815
Freight-Outside Coal	—			—		2,497		—		—			2,497
Miscellaneous Other Income	68,307			13,858		24,358		2,400		(68,139		)	40,784
Gain (Loss) on Sale of Assets	—			5,488		2,033		8		—			7,529
Total Revenue and Other Income	68,307			296,005		521,023		67,906		(68,625		)	884,616
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			30,005		—		—		—			30,005
Transportation, Gathering and Compression	—			68,234		—		—		—			68,234
Production, Ad Valorem, and Other Fees	—			8,486		—		—		—			8,486
Direct Administrative and Selling	—			14,060		—		—		—			14,060
Depreciation, Depletion and Amortization	—			82,538		—		—		—			82,538
Exploration and Production Related Other Costs	—			8,042		—		—		—			8,042
Production Royalty Interests and Purchased Gas Costs	—			15,751		—		—		—			15,751
Other Corporate Expenses	—			13,700		—		—		—			13,700
General and Administrative	—			14,874		—		—		—			14,874
Total Exploration and Production Costs	—			255,690		—		—		—			255,690
Coal Costs
Operating and Other Costs	3,458			—		336,243		—		(485		)	339,216
Royalties and Production Taxes	—			—		23,306		—		—			23,306
Direct Administrative and Selling	—			—		10,479		—		—			10,479
Depreciation, Depletion and Amortization	159			—		64,721		—		—			64,880
Freight Expense	—			—		2,497		—		—			2,497
General and Administrative Costs	—			—		10,434		—		—			10,434
Other Corporate Expenses	10,114			—		—		—		—			10,114
Total Coal Costs	13,731			—		447,680		—		(485		)	460,926
Other Costs
Miscellaneous Operating Expense	23,681			—		6,050		63,243		—			92,974
General and Administrative Costs	—			—		205		220		—			425
Depreciation, Depletion and Amortization	6			—		775		466		—			1,247
Loss on Debt Extinguishment	20,990			—		—		—		—			20,990
Interest Expense	52,907			2,629		1,587		82		(1,808		)	55,397
Total Other Costs	97,584			2,629		8,617		64,011		(1,808		)	171,033
Total Costs And Expenses	111,315			258,319		456,297		64,011		(2,293		)	887,649
(Loss) Earnings Before Income Tax	(43,008		)	37,686		64,726		3,895		(66,332		)	(3,033		)
Income Taxes	(41,363		)	13,281		25,221		1,473		—			(1,388		)
(Loss) Income From Continuing Operations	(1,645		)	24,405		39,505		2,422		(66,332		)	(1,645		)
Income From Discontinued Operations, net	—			—		—		—		—			—
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(1,645	)	$	24,405	$	39,505	$	2,422	$	(66,332	)	$	(1,645	)

Balance Sheet at September 30, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	191,555		$	33,121		$	—		$	887	$	—		$	225,563
Accounts and Notes Receivable:
Trade	—			95,746			—			204,193		—			299,939
Other Receivables	49,930			323,154			5,673			3,895		—			382,652
Inventories	—			14,086			95,450			35,836		—			145,372
Deferred Income Taxes	127,366			365			—			—		—			127,731
Recoverable Income Taxes	57,067			(15,096		)	—			—		—			41,971
Prepaid Expenses	39,202			36,182			24,655			1,828		—			101,867
Total Current Assets	465,120			487,558			125,778			246,639		—			1,325,095
Property, Plant and Equipment:
Property, Plant and Equipment	165,885			7,694,180			6,577,039			26,224		—			14,463,328
Less-Accumulated Depreciation, Depletion and Amortization	118,444			1,410,235			2,950,922			19,743		—			4,499,344
Total Property, Plant and Equipment-Net	47,441			6,283,945			3,626,117			6,481		—			9,963,984
Other Assets:
Investment in Affiliates	12,481,970			92,188			78,231			—		(12,466,880		)	185,509
Other	172,625			23,264			39,822			8,636		—			244,347
Total Other Assets	12,654,595			115,452			118,053			8,636		(12,466,880		)	429,856
Total Assets	$	13,167,156		$	6,886,955		$	3,869,948		$	261,756	$	(12,466,880	)	$	11,718,935
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	102,157		$	400,751		$	93,156		$	14,661	$	—		$	610,725
Accounts Payable (Recoverable)—Related Parties	4,502,239			152,871			(5,286,273		)	65,013		566,150			—
Current Portion Long-Term Debt	1,571			6,590			3,393			671		—			12,225
Short-Term Notes Payable	—			566,150						—		(566,150		)	—
Other Accrued Liabilities	163,415			109,704			329,341			8,244		—			610,704
Current Liabilities of Discontinued Operations	—			—			—			12,992		—			12,992
Total Current Liabilities	4,769,382			1,236,066			(4,860,383		)	101,581		—			1,246,646
Long-Term Debt:	3,125,439			38,907			113,100			1,876		—			3,279,322
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(89,966		)	484,991			—			—		—			395,025
Postretirement Benefits Other Than Pensions	—			—			652,050			—		—			652,050
Pneumoconiosis Benefits	—			—			111,514			—		—			111,514
Mine Closing	—			—			321,776			—		—			321,776
Gas Well Closing	—			120,899			59,621			—		—			180,520
Workers’ Compensation	—			—			73,053			345		—			73,398
Salary Retirement	48,231			—			—			—		—			48,231
Reclamation	—			—			34,499			—		—			34,499
Other	59,471			56,788			5,096			—		—			121,355
Total Deferred Credits and Other Liabilities	17,736			662,678			1,257,609			345		—			1,938,368
Total CONSOL Energy Inc. Stockholders’ Equity	5,254,599			4,949,304			7,359,622			157,954		(12,466,880		)	5,254,599
Total Liabilities and Equity	$	13,167,156		$	6,886,955		$	3,869,948		$	261,756	$	(12,466,880	)	$	11,718,935

Income Statement for the Three Months Ended September 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	$	—		$	193,383		$	203	$	—		$	(805	)	$	192,781
Coal Sales	—			—			479,311		—			—			479,311
Other Outside Sales	—			—			9,702		54,174			—			63,876
Gas Royalty Interests and Purchased Gas Sales	—			17,113			—		—			—			17,113
Freight-Outside Coal	—			—			9,579		—			—			9,579
Miscellaneous Other Income	78,203			11,133			4,783		4,928			(78,225		)	20,822
Gain (Loss) on Sale of Assets	—			1,462			18,401		—			—			19,863
Total Revenue and Other Income	78,203			223,091			521,979		59,102			(79,030		)	803,345
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			23,600			—		—			—			23,600
Transportation, Gathering and Compression	—			46,699			—		—			—			46,699
Production, Ad Valorem, and Other Fees	—			8,033			—		—			—			8,033
Direct Administrative and Selling	—			11,725			—		—			—			11,725
Depreciation, Depletion and Amortization	—			58,998			—		—			—			58,998
Exploration and Production Related Other Costs	—			22,771			—		—			—			22,771
Production Royalty Interests and Purchased Gas Costs	—			13,815			—		—			(10		)	13,805
Other Corporate Expenses	—			26,289			—		—			—			26,289
General and Administrative	—			10,177			—		—			—			10,177
Total Exploration and Production Costs	—			222,107			—		—			(10		)	222,097
Coal Costs
Operating and Other Costs	2,749			—			275,068		—			50,576			328,393
Royalties and Production Taxes	—			—			24,380		—			—			24,380
Direct Administrative and Selling	—			—			11,608		—			—			11,608
Depreciation, Depletion and Amortization	3,116			—			54,149		—			—			57,265
Freight Expense	—			—			9,579		—			—			9,579
General and Administrative Costs	—			—			8,607		—			—			8,607
Other Corporate Expenses	11,145			—			—		—			—			11,145
Total Coal Costs	17,010			—			383,391		—			50,576			450,977
Other Costs
Miscellaneous Operating Expense	33,572			—			4,183		56,091			(18,407		)	75,439
General and Administrative Costs	—			—			141		235			—			376
Depreciation, Depletion and Amortization	172			—			785		510			—			1,467
Interest Expense	52,165			2,578			1,547		13			(3		)	56,300
Total Other Costs	85,909			2,578			6,656		56,849			(18,410		)	133,582
Total Costs And Expenses	102,919			224,685			390,047		56,849			32,156			806,656
Earnings (Loss) Before Income Tax	(24,716		)	(1,594		)	131,932		2,253			(111,186		)	(3,311		)
Income Taxes	38,935			(602		)	31,378		(853		)	—			68,858
(Loss) Income From Continuing Operations	(63,651		)	(992		)	100,554		3,106			(111,186		)	(72,169		)
Income From Discontinued Operations, net	—			—			—		8,120			—			8,120
Net (Loss) Income	(63,651		)	(992		)	100,554		11,226			(111,186		)	(64,049		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(398		)	—		—			—			(398		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(63,651	)	$	(594	)	$	100,554	$	11,226		$	(111,186	)	$	(63,651	)

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 Nine Months Ended September 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	$	—		$	755,337	$	—	$	—		$	(1,938	)	$	753,399
Coal Sales	—			—		1,554,939		—			—			1,554,939
Other Outside Sales	—			—		28,685		184,362			—			213,047
Gas Royalty Interests and Purchased Gas Sales	—			68,773		—		—			—			68,773
Freight-Outside Coal	—			—		22,551		—			—			22,551
Miscellaneous Other Income	329,842			51,688		106,794		7,442			(329,951		)	165,815
Gain (Loss) on Sale of Assets	—			11,560		1,042		13			—			12,615
Total Revenue and Other Income	329,842			887,358		1,714,011		191,817			(331,889		)	2,791,139
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			85,622		—		—			—			85,622
Transportation, Gathering and Compression	—			179,813		—		—			—			179,813
Production, Ad Valorem, and Other Fees	—			28,817		—		—			—			28,817
Direct Administrative and Selling	—			39,216		—		—			—			39,216
Depreciation, Depletion and Amortization	—			225,766		—		—			—			225,766
Exploration and Production Related Other Costs	—			15,765		—		—			—			15,765
Production Royalty Interests and Purchased Gas Costs	—			58,531		—		—			(12		)	58,519
Other Corporate Expenses	—			60,876		—		—			—			60,876
General and Administrative	—			47,755		—		—			—			47,755
Total Exploration and Production Costs	—			742,161		—		—			(12		)	742,149
Coal Costs
Operating and Other Costs	20,060			—		995,483		—			(1,937		)	1,013,606
Royalties and Production Taxes	—			—		77,397		—			—			77,397
Direct Administrative and Selling	—			—		33,589		—			—			33,589
Depreciation, Depletion and Amortization	472			—		185,557		—			—			186,029
Freight Expense	—			—		22,551		—			—			22,551
General and Administrative Costs	—			—		33,397		—			—			33,397
Other Corporate Expenses	41,444			—		—		—			—			41,444
Total Coal Costs	61,976			—		1,347,974		—			(1,937		)	1,408,013
Other Costs
Miscellaneous Operating Expense	63,903			—		21,349		181,349			—			266,601
General and Administrative Costs	—			—		608		651			—			1,259
Depreciation, Depletion and Amortization	19			—		2,437		1,429			—			3,885
Loss on Debt Extinguishment	95,267			—		—		—			—			95,267
Interest Expense	162,729			6,593		5,120		185			(4,088		)	170,539
Total Other Costs	321,918			6,593		29,514		183,614			(4,088		)	537,551
Total Costs And Expenses	383,894			748,754		1,377,488		183,614			(6,037		)	2,687,713
Earnings (Loss) Before Income Tax	(54,052		)	138,604		336,523		8,203			(325,852		)	103,426
Income Taxes	(143,476		)	51,828		96,861		3,102			—			8,315
Income (Loss) From Continuing Operations	89,424			86,776		239,662		5,101			(325,852		)	95,111
Loss From Discontinued Operations, net	—			—		—		(5,687		)	—			(5,687		)
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	89,424		$	86,776	$	239,662	$	(586	)	$	(325,852	)	$	89,424

Income Statement for the Nine Months Ended September 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	$	—		$	534,223		$	203		$	—		$	(2,567	)	$	531,859
Coal Sales	—			—			1,532,280			—			—			1,532,280
Other Outside Sales	—			—			35,941			161,837			—			197,778
Gas Royalty Interests and Purchased Gas Sales	—			51,109			—			—			—			51,109
Freight-Outside Coal	—			—			31,492			—			—			31,492
Miscellaneous Other Income	354,386			29,895			32,129			15,705			(354,386		)	77,729
Gain (Loss) on Sale of Assets	—			7,159			45,049			—			—			52,208
Total Revenue and Other Income	354,386			622,386			1,677,094			177,542			(356,953		)	2,474,455
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			70,835			—			—			—			70,835
Transportation, Gathering and Compression	—			144,002			—			—			—			144,002
Production, Ad Valorem, and Other Fees	—			20,011			—			—			—			20,011
Direct Administrative and Selling	—			34,615			—			—			—			34,615
Depreciation, Depletion and Amortization	—			164,832			—			—			—			164,832
Exploration and Production Related Other Costs	—			43,666			—			—			—			43,666
Production Royalty Interests and Purchased Gas Costs	—			41,196			—			—			(31		)	41,165
Other Corporate Expenses	—			74,239			—			—			—			74,239
General and Administrative	—			29,239			—			—			—			29,239
Total Exploration and Production Costs	—			622,635			—			—			(31		)	622,604
Coal Costs
Operating and Other Costs	5,878			—			874,946			—			112,518			993,342
Royalties and Production Taxes	—			—			79,257			—			—			79,257
Direct Administrative and Selling	—			—			34,744			—			—			34,744
Depreciation, Depletion and Amortization	9,193			—			160,509			—			—			169,702
Freight Expense	—			—			31,492			—			—			31,492
General and Administrative Costs	—			—			27,946			—			—			27,946
Other Corporate Expenses	43,056			—			—			—			—			43,056
Total Coal Costs	58,127			—			1,208,894			—			112,518			1,379,539
Other Costs
Miscellaneous Operating Expense	101,711			—			34,188			165,859			(29,412		)	272,346
General and Administrative Costs	—			—			474			795			—			1,269
Depreciation, Depletion and Amortization	542			—			2,269			1,492			—			4,303
Interest Expense	153,141			6,375			4,868			34			(224		)	164,194
Total Other Costs	255,394			6,375			41,799			168,180			(29,636		)	442,112
Total Costs And Expenses	313,521			629,010			1,250,693			168,180			82,851			2,444,255
Earnings (Loss) Before Income Tax	40,865			(6,624		)	426,401			9,362			(439,804		)	30,200
Income Taxes	118,606			(2,557		)	(14,976		)	(3,542		)	—			97,531
(Loss) Income From Continuing Operations	(77,741		)	(4,067		)	441,377			12,904			(439,804		)	(67,331		)
Loss From Discontinued Operations, net	—			—			—			(11,352		)	—			(11,352		)
Net (Loss) Income	(77,741		)	(4,067		)	441,377			1,552			(439,804		)	(78,683		)
Less: Net Loss Attributable to Noncontrolling Interests	—			(942		)	—			—			—			(942		)
Net (Loss) Income Attributable to CONSOL Energy Shareholders	$	(77,741	)	$	(3,125	)	$	441,377		$	1,552		$	(439,804	)	$	(77,741	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used In) Continuing Operations	$	(87,081	)	$	512,135		$	191,233		$	21,155		$	233,663		$	871,105
Net Cash Used in Discontinued Operating Activities	—			—			—			(20,934		)	—			(20,934		)
Net Cash Provided by (Used In) Operating Activities	$	(87,081	)	$	512,135		$	191,233		$	221		$	233,663		$	850,171
Cash Flows from Investing Activities:
Capital Expenditures	$	(2,314	)	$	(852,097	)	$	(320,196	)	$	—		$	—		$	(1,174,607	)
Proceeds From Sales of Assets	(15,941		)	57,919			99,145			13			—			141,136
Net Investments in Equity Affiliates	—			79,723			28,809			—			—			108,532
Net Cash (Used in) Provided by Continuing Operations	(18,255		)	(714,455		)	(192,242		)	13			—			(924,939		)
Net Cash Used in Discontinued Investing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Investing Activities	$	(18,255	)	$	(714,455	)	$	(192,242	)	$	13		$	—		$	(924,939	)
Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	$	(11,736	)	$	233,663		$	—		$	—		$	(233,663	)	$	(11,736	)
Payments on Miscellaneous Borrowings	(662		)	—			(3,451		)	(56		)	—			(4,169		)
Proceeds from Long-Term Borrowings	1,859,920			—			—			—			—			1,859,920
Payments on Long-Term Borrowings	(1,843,866		)	—			—			—			—			(1,843,866		)
Tax Benefit from Stock-Based Compensation	2,478			—			—			—			—			2,478
Dividends Paid	(43,119		)	—			—			—			—			(43,119		)
Proceeds from Issuance of Common Stock	13,403			—			—			—			—			13,403
Other Financing Activities	—			(4,460		)	4,460			—			—			—
Net Cash (Used in) Provided by Continuing Operations	(23,582		)	229,203			1,009			(56		)	(233,663		)	(27,089		)
Net Cash Used in Discontinued Financing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Financing Activities	$	(23,582	)	$	229,203		$	1,009		$	(56	)	$	(233,663	)	$	(27,089	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	(7,909	)	$	383,504		$	139,014		$	(102,139	)	$	38,500		$	450,970
Net Cash Provided by Discontinued Operating Activities	—			—			—			138,029			—			138,029
Net Cash Provided by (Used in) Operating Activities	$	(7,909	)	$	383,504		$	139,014		$	35,890		$	38,500		$	588,999
Cash Flows from Investing Activities:
Capital Expenditures	$	(15,216	)	$	(669,067	)	$	(336,844	)	$	—		$	—		$	(1,021,127	)
Change in Restricted Cash	—			—			56,410			—			—			56,410
Proceeds From Sales of Assets	—			335,142			129,479			17			—			464,638
Net Investments in Equity Affiliates	—			(30,500		)	12,388			—			—			(18,112		)
Net Cash (Used in) Provided by Continuing Operations	(15,216		)	(364,425		)	(138,567		)	17			—			(518,191		)
Net Cash Used in Discontinued Investing Activities	—			—			—			(41,246		)	—			(41,246		)
Net Cash Used in Investing Activities	$	(15,216	)	$	(364,425	)	$	(138,567	)	$	(41,229	)	$	—		$	(559,437	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	85,500		$	—		$	—		$	(38,500	)	$	47,000
Payments on Miscellaneous Borrowings	(26,591		)	—			(4,690		)	(577		)	—			(31,858		)
Proceeds from Securitization Facility	—			—			—			6,518			—			6,518
Tax Benefit from Stock-Based Compensation	2,316			—			—			—			—			2,316
Dividends (Paid) Received	42,789			(100,000		)	—			—			—			(57,211		)
Proceeds from Issuance of Common Stock	2,698			—			—			—			—			2,698
Proceeds from Issuance of Treasury Stock	609			—			—			—			—			609
Capital Lease Payments	—			(4,084		)	4,084			—			—			—
Net Cash (Used in) Provided by Continuing Operations	21,821			(18,584		)	(606		)	5,941			(38,500		)	(29,928		)
Net Cash Used in Discontinued Financing Activities	—			—			—			(432		)	—			(432		)
Net Cash (Used in) Provided by Financing Activities	$	21,821		$	(18,584	)	$	(606	)	$	5,509		$	(38,500	)	$	(30,360	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(1,645	)	$	24,405		$	39,505	$	2,422	$	(66,332	)	$	(1,645	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	184,154			—			184,154		—		(184,154		)	184,154
Net Increase (Decrease) in the Value of Cash Flow Hedge	39,151			39,151			—		—		(39,151		)	39,151
Reclassification of Cash Flow Hedge from OCI to Earnings	(19,510		)	(19,510		)	—		—		19,510			(19,510		)
Other Comprehensive Income (Loss):	203,795			19,641			184,154		—		(203,795		)	203,795
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	202,150		$	44,046		$	223,659	$	2,422	$	(270,127	)	$	202,150

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(63,651	)	$	(992	)	$	100,554	$	11,226	$	(111,186	)	$	(64,049	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	24,980			—			24,980		—		(24,980		)	24,980
Net Increase (Decrease) in the Value of Cash Flow Hedge	13,246			13,246			—		—		(13,246		)	13,246
Reclassification of Cash Flow Hedge from OCI to Earnings	(24,354		)	(24,354		)	—		—		24,354			(24,354		)
Other Comprehensive Income (Loss):	13,872			(11,108		)	24,980		—		(13,872		)	13,872
Comprehensive Loss (Income)	(49,779		)	(12,100		)	125,534		11,226		(125,058		)	(50,177		)
Less: Comprehensive (Loss) Attributable to Noncontrolling Interest	—			(398		)	—		—		—			(398		)
Comprehensive Loss (Income) Attributable to CONSOL Energy Inc. Shareholders	$	(49,779	)	$	(11,702	)	$	125,534	$	11,226	$	(125,058	)	$	(49,779	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	89,424		$	86,776		$	239,662	$	(586	)	$	(325,852	)	$	89,424
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	185,475			—			185,475		—			(185,475		)	185,475
Net (Decrease) Increase in the Value of Cash Flow Hedge	(20,032		)	(20,032		)	—		—			20,032			(20,032		)
Reclassification of Cash Flow Hedge from OCI to Earnings	3,754			3,754			—		—			(3,754		)	3,754
Other Comprehensive Income (Loss):	169,197			(16,278		)	185,475		—			(169,197		)	169,197
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	258,621		$	70,498		$	425,137	$	(586	)	$	(495,049	)	$	258,621

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(77,741	)	$	(4,067	)	$	441,377	$	1,552	$	(439,804	)	$	(78,683	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	113,641			—			113,641		—		(113,641		)	113,641
Net Increase (Decrease) in the Value of Cash Flow Hedge	40,400			40,400			—		—		(40,400		)	40,400
Reclassification of Cash Flow Hedge from OCI to Earnings	(56,595		)	(56,595		)	—		—		56,595			(56,595		)
Other Comprehensive Income (Loss):	97,446			(16,195		)	113,641		—		(97,446		)	97,446
Comprehensive Income (Loss)	19,705			(20,262		)	555,018		1,552		(537,250		)	18,763
Less: Comprehensive (Loss) Attributable to Noncontrolling Interest	—			(942		)	—		—		—			(942		)
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	19,705		$	(19,320	)	$	555,018	$	1,552	$	(537,250	)	$	19,705

NOTE 17—RELATED PARTY TRANSACTIONS:

CONE Midstream Partners LP

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

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

During the nine months ended September 30, 2014, CONE provided CNX Gas Company gathering services in the ordinary course of business. Gathering services received from CONE were $17,794 and $44,001 for the three and nine months ended September 30, 2014, respectively, and were $9,689 and $24,470 for the three and nine months ended September 30, 2013, respectively, which were included in Exploration and Production Costs - Transportation, Gathering and Compression on the Consolidated Statements of Income.

As of September 30, 2014 and December 31, 2013, CONSOL Energy had a net payable of $11,435 and $5,448, respectively, due to CONE which was comprised of the following items:



	September 30,			December 31,
	2014			2013			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(913	)	$	(2,168	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(122		)	(265		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	(2,789		)	—			Accounts Receivable–Other
CONE Gathering Fee Payable	15,259			7,881			Accounts Payable
Net Payable due to CONE	$	11,435		$	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 Standards 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 EVENTS:

In October 2014, CONSOL Energy sold various non-strategic assets, including various coal reserves and investments in equity affiliates, for total cash proceeds of approximately $71,000 and a note receivable for approximately $12,000. The financial gain for these transactions is approximately $14,000.


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

General

E&P Marketing and Transportation Update:

Third quarter 2014 average dry gas prices, including the impact of our hedging program and net of basis, averaged $3.60 per Mcf. CONSOL's expansion into wet gas production areas provided a liquids value uplift of $0.37 per Mcfe, bringing the overall average sales price to $3.97 per Mcfe. Third quarter 2014 liquids volumes of 6.3 Bcfe were over six times greater than the 2013 third quarter and made up 10% of the company’s total volumes compared with 2% in the third quarter of last year. CONSOL Energy expects to continue to realize 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 actively-monitored hedge program.

CONSOL Energy continues to develop a diversified portfolio of firm transportation capacity to support the three-year production growth plan. In September 2014, the company entered into a precedent agreement with DTE Energy and Spectra Energy for its Nexus project as an anchor shipper to transport gas from the Appalachian Basin to Midwest markets. The pipeline is expected to be placed into service in late 2017.

The Company currently has a total of 1.4 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 0.5 Bcf per day under precedent agreements with several pipeline projects (including the Nexus project) that will be completed over the next few years, and an additional 0.2 Bcf per day of long-term firm sales with major customers that have their own firm capacity. The average demand cost for the existing firm capacity is approximately $0.23 per MMBtu. The average demand cost for existing, plus future, firm capacity is approximately $0.32 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 211 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 also expects to supply volumes to Shell's cracker plant in Monaca, Pennsylvania. 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 Mont Belvieu via the ATEX pipeline. CONSOL will also realize ethane value through blending capabilities. Employing this multi-faceted approach enables us to meet pipeline quality specifications, diversify the ethane portfolio, and maximize our ethane pricing. CONSOL Energy is in active discussions with a number of ethane customers and midstream companies for future outlet opportunities.

Coal Marketing Update:

In the third quarter, CONSOL Energy sold 1 million tons of Buchanan low volatile coal. Despite the recent decrease in the BHP Billiton Mitsubishi Alliance (BMA) settlement price, Buchanan’s low cost position allows the mine to compete, and remain profitable, in the current domestic and worldwide metallurgical markets. CONSOL Energy continues to ship low-vol coal to European and South American end users. CONSOL Energy does continue to focus on expanding domestic metallurgical sales and recently secured additional new contracts with U.S. customers for 2015.

Also in the third quarter, CONSOL Energy exported 200,000 tons of Bailey high-vol coal to existing end users in Korea and Brazil. Prices for high volatile coal remains more stable than other classes of metallurgical coal. End users continue to demand Bailey coal due to its versatility, which allows it to compete as high volatile metallurgical, pulverized coal injection (PCI) and high-Btu thermal coal.

As winter approaches, CONSOL Energy believes that domestic utility market demand, buoyed by utility inventories remaining below normal levels, will support continued spot market and term contracting activity. As CONSOL Energy contracts Bailey coal’s 2015 production, the company is dedicated to placing the tons in markets that provide the most value. For the third quarter of 2014, CONSOL Energy completed sales to six different customers for 2.4 million tons and is currently in negotiations for additional domestic and export shipments end users.

CONSOL Energy 2014 - 2016 Guidance:

Fourth quarter gas production, net to CONSOL Energy, is expected to be approximately 70 – 75 Bcfe. If achieved, this would result in 2014 production of approximately 235 – 240 Bcfe. CONSOL Energy continues to expect its 2015 and 2016 annual gas production to grow by 30%.

As of October 31, 2014, the carry with Noble Energy is suspended and it will remain suspended until average Henry Hub natural gas prices are above $4.00 per million British thermal units (MMBtu) for three consecutive months.

CONSOL Energy’s hedging strategy and formulaic approach for its natural gas portfolio requires entering into hedges that meet certain short and long-term internal pricing parameters. Due to the quantities and types of hedges in place during the quarter, as well as the then-expected future gas prices, CONSOL Energy's hedge position met company requirements, and the company did not add any new hedges during the quarter. 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	235-240	+30%	+30%
Volumes Hedged (Bcf),as of 10/14/14	159.9*	82.6	75.3
Average Hedge Price ($/Mcf)	$4.58	$4.07	$4.17

* Includes 2014 Actual Settlements of 118.2 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




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

COAL DIVISION GUIDANCE

In coal, the lower end of the low-vol guidance range for 2014 has increased slightly to reflect new Atlantic market business, which the company believes will be ongoing. This shift illustrates the expansion of the Buchanan product into new markets. 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 range for 2014 has remained relatively flat.



	Q4 2014		2014		2015
Est. Total Coal Sales	8.0 - 8.4		32.3 - 32.7		31.0 - 35.0
Tonnage: Firm	8.1		32.4		21.1
Price: Sold (firm)	$	62.21	$	63.28	$	64.19
Est. Low-Vol Met Sales	0.7 - 0.9		3.7 - 3.9		3.5 - 5.0
Tonnage: Firm	0.7		3.7		1.0
Est. High-Vol Met Sales	0.3		1.3		1.9
Tonnage: Firm	0.2		1.2		0.3
Est. Thermal Sales	7.0 - 7.2		27.3 - 27.5		25.6 - 28.1
Tonnage: Firm	7.2		27.5		19.8

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 Energy 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 or 2015. 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 0.3 million tons for 2014. WAE has 0.5 million tons and 0.6 million tons for all of 2014, and 2015, respectively.

Results of Operations

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

Net Loss Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $2 million, or a loss of $0.01 per diluted share, for the three months ended September 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $64 million, or a loss of $0.28 per diluted share, for the three months ended September 30, 2013. Net loss attributable to CONSOL Energy shareholders for the three months ended September 30, 2013 included a loss from continuing operations of $72 million, or a loss of $0.31 per diluted share, and income from discontinued operations of $8 million, or income of $0.03 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 $38 million before income tax for the three months ended September 30, 2014 compared to a loss of $2 million before income tax for the three months ended September 30, 2013. Total E&P production was 64.9 Bcfe for the three months ended September 30, 2014 compared to 46.1 Bcfe for the three months ended September 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 September 30,
in thousands (unless noted)	2014		2013		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	5,330		740		4,590			620.3	%
Sales Volume (Mbbls)	888		123		765			622.0	%
Gross Price ($/Bbl)	$	36.00	$	42.54	$	(6.54	)	(15.4	)%
Gross Revenue	$	31,952	$	5,241	$	26,711		509.7	%

Oil:
Sales Volume (MMcfe)	183		148		35			23.6	%
Sales Volume (Mbbls)	31		25		6			24.0	%
Gross Price ($/Bbl)	$	90.12	$	99.24	$	(9.12	)	(9.2	)%
Gross Revenue	$	2,750	$	2,441	$	309		12.7	%

Condensate:
Sales Volume (MMcfe)	815		72		743			1,031.9	%
Sales Volume (Mbbls)	136		12		124			1,033.3	%
Gross Price ($/Bbl)	$	87.96	$	95.28	$	(7.32	)	(7.7	)%
Gross Revenue	$	11,950	$	1,139	$	10,811		949.2	%

GAS
Sales Volume (MMcf)	58,585		45,128		13,457			29.8	%
Sales Price ($/Mcf)	$	3.24	$	3.49	$	(0.25	)	(7.2	)%
Hedging Impact ($/Mcf)	$	0.36	$	0.60	$	(0.24	)	(40.0	)%
Gross Revenue including Hedging Impact	$	211,190	$	184,561	$	26,629		14.4	%

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



	For the Three Months Ended September 30,
	2014		2013		Variance			Percent Change
Average Sales Price (per Mcfe)	$	3.97	$	4.20	$	(0.23	)	(5.5	)%
Average Costs (per Mcfe)	3.12		3.23		(0.11		)	(3.4	)%
Margin	$	0.85	$	0.97	$	(0.12	)	(12.4	)%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $258 million for the three months ended September 30, 2014 compared to $193 million for the three months ended September 30, 2013. The increase was primarily due to the 40.8% increase in total volumes sold offset, in part, by the 5.5% decrease in average price per Mcfe. The decrease in average sales price was primarily due to a $0.25 per Mcf decrease in general market prices for natural gas and a $0.24 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 41.7 Bcf of our produced gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.51 per Mcf. These financial hedges represented approximately 24.0 Bcf of our produced gas sales volumes for the three months ended September 30, 2013 at an average gain of $1.12 per Mcf. The decreases due to general market prices and our hedging program were offset, in part, by the $0.26 per Mcfe increase in sales of NGLs, oil and condensate.

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


•	The improvement in unit costs is primarily due to the increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 47% of gas sales volume for the three months ended September 30, 2014 compared to 38% in the three months ended September 30, 2013


•	The decrease to lifting costs on a per unit basis due to the increase in sales volumes was offset, in part, by an increase in total dollars relating to higher salt water disposal, and well site maintenance costs.


•	The decrease to ad valorem, severance, and other taxes on a per unit basis due to the increase in sales volumes was offset, in part, by an increase in total dollars from the increase in volumes sold and the mix of volumes by state.


•	The decrease to depreciation, depletion and amortization on a per unit basis due to the increase in gas sales volume was offset, in part, by an increase in total dollars as the portion of production from higher investment cost segments continued to grow.


•	Gathering expense per unit increased in the period-to-period comparison due to increased firm transportation costs and increased processing fees associated with natural gas liquids. The increase in unit costs was partially offset by the increase in sales volumes.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $53 million of earnings before income tax for the three months ended September 30, 2014 compared to $64 million for the three months ended September 30, 2013. The total coal division sold 7.8 million tons of coal produced from CONSOL Energy mines for the three months ended September 30, 2014 compared to 6.9 million tons for the three months ended September 30, 2013. Current period sales tons were comprised of 85% thermal and 15% metallurgical. Prior period sales tons were comprised of 78% thermal and 22% 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 September 30,
	2014		2013		Variance			Percent Change
Average Sales Price per ton sold	$	62.32	$	68.23	$	(5.91	)	(8.7	)%
Average Costs of Goods Sold per ton	49.93		50.70		(0.77		)	(1.5	)%
Margin	$	12.39	$	17.53	$	(5.14	)	(29.3	)%

The lower average sales price per ton sold reflects a continuing decline in the global metallurgical coal markets, an oversupply in coal used in steelmaking, and lower thermal coal pricing due to the continuing roll-off of some higher-priced legacy contracts. The coal division priced 1.3 million tons on the export market at an average sales price of $65.15 per ton for the three months ended September 30, 2014 compared to 1.8 million tons at an average price of $70.48 per ton for the three months ended September 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 decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. The decrease was offset, in part, by geologic issues at the Enlow Fork Mine and Harvey Mine.

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

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 September 30,
(in millions)	2014		2013		Variance			Percent Change
Continuing Operations General and Administrative Expenses	$	26	$	19	$	7		36.8	%
Discontinued Operations General and Administrative Expenses	—		9		(9		)	(100.0	)%
Total Company General and Administrative Expense	$	26	$	28	$	(2	)	(7.1	)%

Overall, total Company General and Administrative Expenses decreased $2 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of five of our West Virginia coal mines. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

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 $36 million for the three months ended September 30, 2014 compared to $33 million for the three months ended September 30, 2013. The increase of $3 million for total CONSOL Energy continuing operations expense was primarily due to an increase in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31, partially offset by required pension settlement accounting which resulted in $5 million of expense during three months ended September 30, 2014 and $6 million of expense in three months ended September 30, 2013. Pension settlement accounting 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. Not included in the long-term liability expense totals discussed above are curtailment gains of $36 million, and $46 million of expense for cash payments made to active employees both of which arose from modifications to the OPEB and Pension plans during the three months ended September 30, 2014. The pension settlement expense, cash payments and curtailment gains were not allocated to individual operating segments and are therefore not included in unit costs presented for the E&P or Coal divisions. 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.

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

The E&P segment contributed $38 million to earnings before income tax for the three months ended September 30, 2014 compared to a loss before income tax of $2 million in the three months ended September 30, 2013. Variances by the individual E&P segments are discussed below.



	For the Three Months Ended												Difference to Three Months Ended
	September 30, 2014												September 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	$	110	$	82	$	25		$	40		$	257	$	38		$	(1	)	$	(8	)	$	36		$	65
Related Party	—		1		—			—			1		—			—			—			—			—
Total Outside Sales	110		83		25			40			258		38			(1		)	(8		)	36			65
Gas Royalty Interest	—		—		—			18			18		—			—			—			3			3
Purchased Gas	—		—		—			1			1		—			—			—			(1		)	(1		)
Other Income	—		—		—			19			19		—			—			—			6			6
Total Revenue and Other Income	110		83		25			78			296		38			(1		)	(8		)	44			73
Lifting	6		9		11			4			30		1			1			2			3			7
Ad Valorem, Severance, and Other Taxes	5		3		1			(1		)	8		2			—			(1		)	(1		)	—
Gathering	29		27		7			5			68		18			(1		)	—			4			21
E&P Direct Administrative, Selling & Other	9		2		1			2			14		3			—			(1		)	—			2
Depreciation, Depletion and Amortization	34		22		14			13			83		15			—			(1		)	10			24
General & Administration	—		—		—			15			15		—			—			—			5			5
Gas Royalty Interest	—		—		—			15			15		—			—			—			2			2
Purchased Gas	—		—		—			1			1		—			—			—			—			—
Exploration and Other Costs	—		—		—			8			8		—			—			—			(15		)	(15		)
Other Corporate Expenses	—		—		—			13			13		—			—			—			(13		)	(13		)
Interest Expense	—		—		—			3			3		—			—			—			—			—
Total Cost	83		63		34			78			258		39			—			(1		)	(5		)	33
Earnings Before Income Tax	$	27	$	20	$	(9	)	$	—		$	38	$	(1	)	$	(1	)	$	(7	)	$	49		$	40

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $27 million to the total Company earnings before income tax for the three months ended September 30, 2014 compared to $28 million for the three months ended September 30, 2013.



	For the Three Months Ended September 30,
	2014		2013		Variance			Percent Change
Marcellus Gas - Gas Sales Volumes (Bcf)	27.0		16.5		10.5			63.6	%
NGLs Sales Volumes (Bcfe)*	3.3		0.8		2.5			312.5	%
Condensate Sales Volumes (Bcfe)*	0.4		0.1		0.3			300.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	30.7		17.4		13.3			76.4	%

Average Sales Price - Gas (Mcf)	$	2.83	$	3.56	$	(0.73	)	(20.5	)%
Hedging Impact - Gas (Mcf)	$	0.39	$	0.43	$	(0.04	)	(9.3	)%
Average Sales Price - NGLs (Mcfe)*	$	5.34	$	7.09	$	(1.75	)	(24.7	)%
Average Sales Price - Condensate (Mcfe)*	$	14.52	$	16.29	$	(1.77	)	(10.9	)%

Total Average Marcellus sales price (per Mcfe)	$	3.58	$	4.16	$	(0.58	)	(13.9	)%
Average Marcellus lifting costs (per Mcfe)	$	0.18	$	0.29	$	(0.11	)	(37.9	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.15	$	0.17	$	(0.02	)	(11.8	)%
Average Marcellus gathering costs (per Mcfe)	$	0.95	$	0.66	$	0.29		43.9	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.30	$	0.34	$	(0.04	)	(11.8	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.11	$	1.09	$	0.02		1.8	%
Total Average Marcellus costs (per Mcfe)	$	2.69	$	2.55	$	0.14		5.5	%
Average Margin for Marcellus (per Mcfe)	$	0.89	$	1.61	$	(0.72	)	(44.7	)%

* 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 NGLs, condensate, and natural gas prices.

The Marcellus segment sales revenues were $110 million for the three months ended September 30, 2014 compared to $72 million for the three months ended September 30, 2013. The $38 million increase is primarily due to a 76.4% increase in total volumes sold offset, in part, by a 13.9% decrease in total average sales price in the period-to-period comparison. The 13.3 Bcfe increase in sales volumes is primarily due to additional wells coming online from our ongoing drilling program. The $0.58 per Mcfe decrease in Marcellus total average sales price was primarily the result of the $0.73 per Mcf decrease in gas market prices and a $0.04 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 19.0 Bcf of our produced Marcellus gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.55 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 6.4 Bcf at an average gain of $1.11 per Mcf. The decrease in average sales price was offset, in part, by an uplift from an additional 2.8 Bcfe, or $0.19 per Mcfe, of NGLs and condensate sales volumes.

Total costs for the Marcellus segment were $83 million for the three months ended September 30, 2014 compared to $44 million for the three months ended September 30, 2013. The increase in total dollars and unit costs for the Marcellus segment is due to the following items:

•Marcellus lifting costs were $6 million for the three months ended September 30, 2014 compared to $5 million for the three months ended September 30, 2013. The increase in total dollars primarily relates to an increase in contract services relating to well tending and well site maintenance, which is a direct result of the increase in the number of wells in production. The decrease in unit costs is due to the increase in sales volumes during the current period.

•Marcellus ad valorem, severance and other taxes were $5 million for the three months ended September 30, 2014 compared to $3 million for the three months ended September 30, 2013. The increase in total dollars is primarily due to an increase in severance tax expense caused by the 76.4% increase in sales volumes during the current period offset, in part, by the 20.5% 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 $29 million for the three months ended September 30, 2014 compared to $11 million for the three months ended September 30, 2013. Total dollars increased primarily due to the 76.4% increase in sales volumes which resulted in increased related party gathering fees, increased processing fees associated with NGLs and an increase in utilized firm transportation expenses. The impact on average unit costs due to the total dollar increase was offset, in part, by the higher sales volumes.

•Marcellus direct administrative, selling and other costs were $9 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 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 $34 million for the three months ended September 30, 2014 compared to $19 million for the three months ended September 30, 2013. There was approximately $33 million, or $1.09 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2014. There was approximately $19 million, or $1.08 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2013. There was $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 September 30, 2014. There was less than $1 million, or $0.01 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 September 30, 2013.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $20 million to the total Company earnings before income tax for the three months ended September 30, 2014 compared to $21 million for the three months ended September 30, 2013.



	For the Three Months Ended September 30,
	2014		2013		Variance			Percent Change
CBM Gas - Gas Sales Volumes (Bcf)	20.0		21.0		(1.0		)	(4.8	)%

Average Sales Price - Gas (Mcf)	$	3.79	$	3.40	$	0.39		11.5	%
Hedging Impact - Gas (Mcf)	$	0.38	$	0.59	$	(0.21	)	(35.6	)%

Total Average CBM sales price (per Mcf)	$	4.17	$	3.99	$	0.18		4.5	%
Average CBM lifting costs (per Mcf)	$	0.46	$	0.39	$	0.07		17.9	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.13	$	0.12	$	0.01		8.3	%
Average CBM gathering costs (per Mcf)	$	1.36	$	1.31	$	0.05		3.8	%
Average CBM direct administrative, selling & other costs (per Mcf)	$	0.13	$	0.11	$	0.02		18.2	%
Average CBM depreciation, depletion and amortization costs (per Mcf)	$	1.10	$	1.06	$	0.04		3.8	%
Total Average CBM costs (per Mcf)	$	3.18	$	2.99	$	0.19		6.4	%
Average Margin for CBM (per Mcf)	$	0.99	$	1.00	$	(0.01	)	(1.0	)%

CBM sales revenues were $83 million in the three months ended September 30, 2014 compared to $84 million for the three months ended September 30, 2013. The $1 million decrease was primarily due to the 4.8% decrease in volumes sold offset, in part, by the 4.5% increase in total average sales price per Mcf. CBM sales volumes decreased 1.0 Bcf for the three months ended September 30, 2014 compared to the 2013 period primarily due to normal well declines without a corresponding amount of additional wells drilled. The decrease in wells drilled is due to the Company's current focus on Marcellus production. The decline in wells drilled is also due to the decline in coal production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price increased $0.18 per Mcf primarily due to a $0.39 per Mcf increase in average market prices offset, in part, by a $0.21 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 17.8 Bcf of our produced CBM gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.42 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 13.8 Bcf at an average gain of $0.89 per Mcf.

Total costs for the CBM segment were $63 million for the three months ended September 30, 2014 and September 30, 2013. The increase in unit costs for the CBM segment was due to the following items:

•CBM lifting costs were $9 million for the three months ended September 30, 2014 compared to $8 million for the three months ended September 30, 2013. The increase in total dollars was primarily due to an increase in well tending and repair and maintenance costs. The $0.07 per Mcf increase in unit costs was primarily due to the decrease in gas sales volumes.

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

•CBM gathering costs were $27 million for the three months ended September 30, 2014 compared to $28 million for the three months ended September 30, 2013. The decrease in total dollars was due to lower utilized firm transportation expense resulting from the decrease in sale volumes. The decrease was offset, in part, by an increase in pipeline maintenance. Improvements in unit costs due to the decrease in total dollars were more than offset by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $2 million for the three months ended September 30, 2014 and September 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 September 30, 2014 and September 30, 2013. There was approximately $15 million, or $0.73 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended September 30, 2014. The production portion of depreciation,

depletion and amortization was $15 million, or $0.74 per unit-of-production in the three months ended September 30, 2013. There was approximately $7 million, or $0.37 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended September 30, 2014. The non-production related depreciation, depletion and amortization was $7 million, or $0.32 per Mcf for the three months ended September 30, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $9 million for the three months ended September 30, 2014 compared to a loss before income tax of $2 million for the three months ended September 30, 2013.



	For the Three Months Ended September 30,
	2014			2013			Variance			Percent Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)	6.6			6.7			(0.1		)	(1.5	)%
Oil Sales Volumes (Bcfe)*	0.1			0.1			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	6.7			6.8			(0.1		)	(1.5	)%

Average Sales Price - Gas (Mcf)	$	3.17		$	3.55		$	(0.38	)	(10.7	)%
Hedging Impact - Gas (Mcf)	$	0.38		$	1.11		$	(0.73	)	(65.8	)%
Average Sales Price - Oil (Mcfe)*	$	14.73		$	17.35		$	(2.62	)	(15.1	)%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	3.76		$	4.85		$	(1.09	)	(22.5	)%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.59		$	1.36		$	0.23		16.9	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)	$	0.09		$	0.27		$	(0.18	)	(66.7	)%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.11		$	1.01		$	0.10		9.9	%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.19		$	0.37		$	(0.18	)	(48.6	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.16		$	2.15		$	0.01		0.5	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.14		$	5.16		$	(0.02	)	(0.4	)%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(1.38	)	$	(0.31	)	$	(1.07	)	(345.2	)%

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

Shallow Oil and Gas sales revenues were $25 million for the three months ended September 30, 2014 compared to $33 million for the three months ended September 30, 2013. The $8 million decrease was due to a 1.5% decrease in total volumes sold and a 22.5% 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 $0.73 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 3.8 Bcf of our produced shallow oil and gas sales volumes for the three months ended September 30, 2014 at an average gain of $0.67 per Mcf. For the three months ended September 30, 2013, these financial hedges represented approximately 3.8 Bcf at an average gain of $1.96 per Mcf. The decrease in average sales price was also the result of a $0.38 per Mcf decrease in average gas market prices.

Total costs for the shallow oil and gas segment were $34 million for the three months ended September 30, 2014 compared to $35 million for the three months ended September 30, 2013. The decrease in total dollars and unit costs for the shallow oil and gas segment is due to the following items:

•Shallow Oil and Gas lifting costs were $11 million for the three months ended September 30, 2014 compared to $9 million for the three months ended September 30, 2013. The $2 million increase in total dollars is primarily due to an increase in environmental compliance, pumping and swabbing, and general well site maintenance expenses. Unit costs were also negatively impacted by the decrease in gas sales volumes.

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

primarily due to the decrease in gas sales volumes and the decrease in total 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 $7 million for the three months ended September 30, 2014 and September 30, 2013. The impairment in unit costs was due to the decrease in gas sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $1 million for the three months ended September 30, 2014 compared to $2 million for the three months ended September 30, 2013. The $1 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 $14 million for the three months ended September 30, 2014 compared to $15 million for the three months ended September 30, 2013. There was approximately $13 million, or $1.90 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2014. There was approximately $13 million, or $1.91 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended September 30, 2013. There was approximately $1 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 three months ended September 30, 2014. There was $2 million, or $0.24 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 September 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 Utica Shale and the Chattanooga Shale in Tennessee. Revenue from Utica Shale operations was approximately $36 million for the three months ended September 30, 2014 compared to $1 million for the three months ended September 30, 2013. Revenue from other Shale operations was $4 million for the three months ended September 30, 2014 compared to $3 million for the three months ended September 30, 2013. Total costs related to Utica Shale operations were $16 million for the three months ended September 30, 2014 compared to $1 million for the three months ended September 30, 2013. Total costs related to other Shale operations were $7 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and 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 September 30, 2014 compared to $15 million for the three months ended September 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 September 30,
	2014		2013		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	5.5		3.5		2.0			57.1	%
Average Sales Price Per thousand cubic feet	$	3.21	$	4.41	$	(1.20	)	(27.2	)%

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



	For the Three Months Ended September 30,
	2014		2013		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.4		0.3		0.1			33.3	%
Average Sales Price Per thousand cubic feet	$	3.08	$	5.13	$	(2.05	)	(40.0	)%

Other income was $19 million for the three months ended September 30, 2014 compared to $13 million for the three months ended September 30, 2013. The $6 million increase was primarily due to the following items:


•	Other income increased $3 million primarily due to an increase in revenue related to certain gathering arrangments.


•	Earnings from our equity affiliates increased $5 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.


•	Gain on property sales increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	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 $2 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 $15 million for the three months ended September 30, 2014 compared to $10 million for the three months ended September 30, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net 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 $15 million for the three months ended September 30, 2014 compared to $13 million for the three months ended September 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 September 30,
	2014		2013		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	5.5		3.5		2.0			57.1	%
Average Cost Per thousand cubic feet sold	$	2.70	$	3.66	$	(0.96	)	(26.2	)%

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



	For the Three Months Ended September 30,
	2014		2013		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.4		0.3		0.1			33.3	%
Average Cost Per thousand cubic feet sold	$	2.42	$	3.01	$	(0.59	)	(19.6	)%

Exploration and other costs were $8 million for the three months ended September 30, 2014 compared to $23 million for the three months ended September 30, 2013. The $15 million decrease is due to the following items:



	For the Three Months Ended September 30,
(in millions)	2014		2013		Variance			Percent Change
Marcellus Title Defects	$	—	$	12	$	(12	)	(100.0	)%
Seismic Activity	1		3		(2		)	(66.7	)%
Lease Expiration Costs	3		3		—			—	%
Other	4		5		(1		)	(20.0	)%
Total Exploration and Other Costs	$	8	$	23	$	(15	)	(65.2	)%


•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $12 million for the three months ended September 30, 2013.


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


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary lease term to expire because of unfavorable drilling economics and remained consistent in the period-to-period comparison.


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

Other corporate expenses were $13 million for the three months ended September 30, 2014 compared to $26 million for the three months ended September 30, 2013. The $13 million decrease was made up of the following items:



	For the Three Months Ended September 30,
(in millions)	2014			2013		Variance			Percent Change
Litigation Settlements	$	(5	)	$	—	$	(5	)	(100.0	)%
Unutilized Firm Transportation and Processing Fees	9			12		(3		)	(25.0	)%
Short-term Incentive Compensation	4			7		(3		)	(42.9	)%
Bank Fees	—			2		(2		)	(100.0	)%
Stock-based Compensation	3			4		(1		)	(25.0	)%
Other	2			1		1			100.0	%
Total Other Corporate Expenses	$	13		$	26	$	(13	)	(50.0	)%


•	Litigation settlements decreased $5 million due to various activities that occurred in the current period, none of which were individually material.


•	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 $3 million decrease is primarily due to a decrease in 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, compliance and unit costs. Short-term incentive compensation expense decreased $3 million due to lower projected payouts in the current period.


•	Bank fees decreased $2 million due to a reduction in revolver related fees. The CNX Gas revolver was amended and restated on June 18, 2014.


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


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

Interest expense related to the gas segment remained consistent at $3 million for the three months ended September 30, 2014 and September 30, 2013.

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

The coal segment contributed $53 million of earnings before income tax in the three months ended September 30, 2014 compared to $64 million in the three months ended September 30, 2013. Variances by the individual coal segments are discussed below.



	For the Three Months Ended														Difference to Three Months Ended
	September 30, 2014														September 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	$	398		$	15	$	70		$	—		$	483		$	46		$	(7	)	$	(28	)	$	—		$	11
Purchased Coal	—			—		—			1			1			—			—			—			(5		)	(5		)
Total Outside Sales	398			15		70			1			484			46			(7		)	(28		)	(5		)	6
Freight Revenue	—			—		—			2			2			—			—			—			(8		)	(8		)
Other Income	—			3		—			23			26			(1		)	3			—			(3		)	(1		)
Total Revenue and Other Income	398			18		70			26			512			45			(4		)	(28		)	(16		)	(3		)
Costs and Expenses:
Beginning inventory costs	12			—		12			—			24			(20		)	—			3			—			(17		)
Total direct operating costs	205			6		31			33			275			47			(5		)	(14		)	(4		)	24
Total royalty/production taxes	18			1		4			—			23			2			—			(2		)	(1		)	(1		)
Total direct services to operations	32			1		6			25			64			—			(1		)	(1		)	(11		)	(13		)
Total retirement and disability	24			1		4			1			30			9			—			(2		)	(2		)	5
Depreciation, depletion and amortization	42			1		11			11			65			10			(1		)	—			(2		)	7
Ending inventory costs	(17		)	—		(7		)	—			(24		)	11			—			—			—			11
Total Costs and Expenses	316			10		61			70			457			59			(7		)	(16		)	(20		)	16
Freight Expense	—			—		—			2			2			—			—			—			(8		)	(8		)
Total Costs	316			10		61			72			459			59			(7		)	(16		)	(28		)	8
Earnings (Loss) Before Income Taxes	$	82		$	8	$	9		$	(46	)	$	53		$	(14	)	$	3		$	(12	)	$	12		$	(11	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $82 million to total Company earnings before income tax for the three months ended September 30, 2014 and $96 million for the three months ended September 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 September 30,
	2014		2013		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	6.6		5.4		1.2			22.2	%
Average Sales Price Per Thermal Ton Sold	$	60.77	$	65.07	$	(4.30	)	(6.6	)%

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

Total Direct Operating Costs Per Thermal Ton Produced	$	30.68	$	29.38	$	1.30		4.4	%
Total Royalty/Production Taxes Per Thermal Ton Produced	2.69		2.99		(0.30		)	(10.0	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.75		5.99		(1.24		)	(20.7	)%
Total Retirement and Disability Per Thermal Ton Produced	3.55		2.77		0.78			28.2	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	6.35		5.84		0.51			8.7	%
Total Production Costs Per Thermal Ton Produced	$	48.02	$	46.97	$	1.05		2.2	%

Ending Inventory Costs Per Thermal Ton	$	48.22	$	53.04	$	(4.82	)	(9.1	)%

Total Costs Per Thermal Ton Sold	$	48.30	$	47.45	$	0.85		1.8	%
Average Margin Per Thermal Ton Sold	$	12.47	$	17.62	$	(5.15	)	(29.2	)%

Thermal coal outside sales revenue was $398 million for the three months ended September 30, 2014 compared to $352 million for the three months ended September 30, 2013. The $46 million increase was attributable to a 1.2 million increase in tons sold offset, in part, by a $4.30 per ton lower average sales price. Thermal coal pricing was lower because of the roll-off of some higher-priced legacy sales contracts. The decrease in average sales price was offset, in part, by 0.4 million tons of thermal coal being priced on the export market at an average sales price of $70.95 per ton for the three months ended September 30, 2014 compared to 0.6 million tons at an average price of $64.11 per ton for the three months ended September 30, 2013.

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 $316 million for the three months ended September 30, 2014, or $59 million higher than the $257 million for the three months ended September 30, 2013. Total cost of goods sold for thermal coal was $48.30 per ton in the three months ended September 30, 2014 compared to $47.45 per ton in the three months ended September 30, 2013. The increase in total dollars and unit costs was primarily due to various maintenance projects at Bailey Mine related to an additional longwall overhaul, a belt repair project, and six thousand additional continuous miner footage. The additional continuous miner footage resulted in additional roof support, haulage, and mine maintenance costs. Unit costs were also negatively impacted in the current period due to geological conditions at Enlow Fork Mine and Harvey Mine. The increase in unit costs was partially offset by the 22.2% increase in thermal tons sold.

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 September 30, 2014 compared to $5 million for the three months ended September 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 September 30,
	2014		2013		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.2		0.4		(0.2		)	(50.0	)%
Average Sales Price Per High Vol Met Ton Sold	$	72.76	$	60.13	$	12.63		21.0	%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	29.68	$	30.20	$	(0.52	)	(1.7	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	2.53		2.82		(0.29		)	(10.3	)%
Total Direct Services to Operations Per High Vol Met Ton Produced	4.82		5.33		(0.51		)	(9.6	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.63		2.93		0.70			23.9	%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	6.69		5.93		0.76			12.8	%
Total Production Costs Per High Vol Met Ton Produced	$	47.35	$	47.21	$	0.14		0.3	%

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

Total Costs Per High Vol Met Ton Sold	$	47.35	$	47.21	$	0.14		0.3	%
Margin Per High Vol Met Ton Sold	$	25.41	$	12.92	$	12.49		96.7	%

High volatile metallurgical coal outside sales revenue was $15 million for the three months ended September 30, 2014 compared to $22 million for the three months ended September 30, 2013. The $7 million decrease was primarily attributable to the 0.2 million decrease in tons sold offset, in part, by the $12.63 per ton increase in average sales price. Average sales prices for high volatile metallurgical coal primarily increased in the period-to-period comparison due to CONSOL Energy pricing 0.2 million tons of high volatile metallurgical coal in the export market at an average sales price of $72.76 per ton for the three months ended September 30, 2014 compared to 0.4 million tons at an average price of $60.13 per ton for the three months ended September 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 $10 million for the three months ended September 30, 2014, or $7 million lower than the $17 million for the three months ended September 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $47.35 per ton in the three months ended September 30, 2014 compared to $47.21 per ton in the three months ended September 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 September 30, 2014 compared to $21 million in the three months ended September 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 September 30,
	2014		2013		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	1.0		1.1		(0.1		)	(9.1	)%
Average Sales Price Per Low Vol Met Ton Sold	$	70.50	$	85.77	$	(15.27	)	(17.8	)%

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

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	33.58	$	41.08	$	(7.50	)	(18.3	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	4.36		5.16		(0.80		)	(15.5	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	6.57		5.85		0.72			12.3	%
Total Retirement and Disability Per Low Vol Met Ton Produced	4.57		5.57		(1.00		)	(18.0	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	10.96		9.67		1.29			13.3	%
Total Production Costs Per Low Vol Met Ton Produced	$	60.04	$	67.33	$	(7.29	)	(10.8	)%

Ending Inventory Costs Per Low Vol Met Ton	$	52.53	$	65.42	$	(12.89	)	(19.7	)%

Total Costs Per Low Vol Met Ton Sold	$	61.29	$	67.18	$	(5.89	)	(8.8	)%
Margin Per Low Vol Met Ton Sold	$	9.21	$	18.59	$	(9.38	)	(50.5	)%

Low volatile metallurgical coal outside sales revenue was $70 million for the three months ended September 30, 2014 compared to $98 million for the three months ended September 30, 2013. The $28 million decrease was attributable to a $15.27 per ton lower average sales price and a 0.1 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the continued weakening in the global metallurgical coal market and the oversupply of coal used in steelmaking.

Total cost of goods sold for low volatile metallurgical coal was $61 million for the three months ended September 30, 2014, or $16 million lower than the $77 million for the three months ended September 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $61.29 per ton in the three months ended September 30, 2014 compared to $67.18 per ton in the three months ended September 30, 2013. The decrease in total dollars and unit costs per low volatile metallurgical ton sold was primarily due to lower royalty and production taxes, lower wage and wage related expenses, and a reduction in the number of degas wells drilled. These decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. Part of the cost control measures included a decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. These improvements were offset, in part, by lower tons sold.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $46 million for the three months ended September 30, 2014 compared to a loss before income tax of $58 million for the three months ended September 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. Purchased coal sales are offset by purchased coal expense. The revenues were $1 million for the three months ended September 30, 2014 compared to $6 million for the three months ended September 30, 2013. The decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

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 $2 million for the three months ended September 30, 2014 compared to $10 million for the three months ended September 30, 2013. The decrease in freight revenue was due to lower shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $23 million for the three months ended September 30, 2014 compared to $26 million for the three months ended September 30, 2013. The change is due to the following items:



	For the Three Months Ended September 30,
(in millions)	2014		2013			Variance
Gain on Sale of Assets	$	2	$	18		$	(16	)
Royalty Income	5		4			1
Equity in earnings of affiliates	4		(2		)	6
Rental Income	10		1			9
Other	2		5			(3		)
Total Other Income Coal Segment	$	23	$	26		$	(3	)

•

Gain on sale of assets decreased $16 million primarily due to the following activity during the three months ended September 30, 2013: the sale of 1.5MM tons of Pittsburgh 8 Coal that CONSOL Energy controlled in Belmont County, OH, resulting in a gain of $2 million; and the sale of a 50% interest in a joint venture in Alberta, Canada, resulting in a gain of $15 million. No such transactions were entered into during the three months ended September 30, 2014.


•	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 increased $6 million due to various transactions completed by our equity partners, none of which were individually material.


•	Rental income increased $9 million due to equipment subleased to a third-party. These arrangements began in December 2013.


•	Other income decreased $3 million due to various items, none of which were individually significant.

Other coal segment total costs were $72 million for the three months ended September 30, 2014 compared to $100 million for the three months ended September 30, 2013. The decrease of $28 million was primarily due to the following items:



	For the Three Months Ended September 30,
(in millions)	2014		2013		Variance
Litigation Settlements	$	—	$	13	$	(13	)
Purchased Coal	2		11		(9		)
Freight Expense	2		10		(8		)
Depreciation, Depletion, and Amortization	6		9		(3		)
Closed and Idle Mines	25		27		(2		)
Stock-based and Incentive Compensation	10		11		(1		)
General and Administrative Expense	10		9		1
Lease Rental Expense	6		—		6
Other	11		10		1
Total Other Coal Segment Costs	$	72	$	100	$	(28	)


•	Litigation settlements decreased $13 million primarily due to a specific settlement that occurred in the third quarter of 2013.


•	Purchased coal costs decreased $9 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.

•

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.


•	Depreciation, Depletion, and Amortization decreased $3 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.


•	Closed and idle mine costs decreased approximately $2 million due to various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material.


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


•	General and Administrative Expense related to the other coal segment increased by $1 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 Loss Attributable to CONSOL Energy Shareholders" of this quarterly report for detailed cost explanations.


•	Lease rental expense increased $6 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 $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the three months ended September 30, 2014 compared to the three months ended September 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 $93 million for the three months ended September 30, 2014 compared to a loss before income tax of $66 million for the three months ended September 30, 2013. The other segment also includes total Company income tax benefit of $1 million for the three months ended September 30, 2014 compared to an income tax expense of $69 million for the three months ended September 30, 2013.



	For the Three Months Ended September 30,
(in millions)	2014			2013			Variance			Percent Change
Sales—Outside	$	74		$	64		$	10		15.6	%
Other Income	1			—			1			100.0	%
Total Revenue	75			64			11			17.2	%
Cost of Goods Sold and Other Charges	94			76			18			23.7	%
Depreciation, Depletion & Amortization	1			1			—			—	%
Loss on Debt Extinguishment	21			—			21			100.0	%
Interest Expense	52			53			(1		)	(1.9	)%
Total Costs	168			130			38			29.2	%
Loss Before Income Tax	(93		)	(66		)	(27		)	40.9	%
Income Tax	(1		)	69			(70		)	(101.4	)%
Net Loss	$	(92	)	$	(135	)	$	43		31.9	%

Industrial supplies:

Outside Sales from industrial supplies were $66 million for the three months ended September 30, 2014, compared to $54 million for the three months ended September 30, 2013. The increase of $12 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $63 million for the three months ended September 30, 2014, compared to $53 million for the three months ended September 30, 2013. The increase of $10 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 $8 million for the three months ended September 30, 2014, compared to $10 million for the three months ended September 30, 2013. The decrease of $2 million was primarily attributable to decreased thru-put volumes for the quarter.

Total costs related to terminal activity were $6 million for the three months ended September 30, 2014, compared to $8 million for the three months ended September 30, 2013. Costs decreased $2 million due to lower per ton thru-put costs and a decrease in thru-put volumes.

Miscellaneous other:

Other income was $1 million for the three months ended September 30, 2014, and less than $1 million for the three months ended September 30, 2013. The increase is due to various items in both periods, none of which were individually material.

Other corporate costs were $99 million for the three months ended September 30, 2014 compared to $69 million for the three months ended September 30, 2013. Other corporate costs increased due to the following items:



	For the Three Months Ended September 30,
(in millions)	2014		2013		Variance
Loss on Debt Extinguishment	$	21	$	—	$	21
Long-Term Liability Plan Changes	10		—		10
Bank Fees	4		4		—
Interest Expense	52		53		(1		)
Pension Settlement	5		6		(1		)
Other	7		6		1
	$	99	$	69	$	30


•	Loss on Debt Extinguishment of $21 million was recognized in the three months ended September 30, 2014 related to the early extinguishment of debt due to the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 1.075%. No such transactions occurred in the prior period.


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


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


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

•

Pension Settlement expense is required when the lump sum distributions made for a given plan year exceed the total of the service and interest costs for that same plan year. 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.


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

Income Taxes:

The effective income tax rate was 28.4% for the three months ended September 30, 2014 compared to (2,079.7)% for the three months ended September 30, 2013. The effective rates for the three months ended September 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, CONSOL Energy was required to file amended state income tax returns. In the three months ended September 30, 2014, the Company filed the required amended returns and realized a discrete state income tax charge of $0.4 million which was offset by a federal income tax benefit of $0.1 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 September 30,
(in millions)	2014			2013			Variance			Percent Change
Total Company Loss Before Income Tax	$	(3	)	$	(3	)	$	—		—	%
Income Tax (Benefit) Expense	$	(1	)	$	69		$	(70	)	(102.0	)%
Effective Income Tax Rate	28.4		%	(2,079.7		)%	2,108.1		%

Results of Operations

Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

Net Income (Loss) Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $89 million, or income of $0.39 per diluted share, for the nine months ended September 30, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $78 million, or a loss of $0.34 per diluted share, for the nine months ended September 30, 2013. Included in net income was income from continuing operations of $95 million, or income of $0.41 per diluted share, for the nine months ended September 30, 2014. There was a loss from continuing operations of $67 million, or a loss of $0.29 per diluted share, for the nine months ended September 30, 2013. Also included in net income is a loss from discontinued operations of $6 million, or a loss of $0.02 per diluted share, for the nine months ended September 30, 2014. There was a loss from discontinued operations of $11 million, or a loss of $0.05 per diluted share, for the nine months ended September 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 $139 million before income tax for the nine months ended September 30, 2014 compared to a loss of $7 million before income tax for the nine months ended September 30, 2013. Total E&P production was 165.2 Bcfe for the nine months ended September 30, 2014 compared to 123.9 Bcfe for the nine months ended September 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 Nine Months Ended September 30,
in thousands (unless noted)	2014			2013		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	8,818			1,505		7,313			485.9	%
Sales Volume (Mbbls)	1,470			251		1,219			485.7	%
Gross Price ($/Bbl)	$	42.30		$	48.66	$	(6.36	)	(13.1	)%
Gross Revenue	$	62,148		$	12,209	$	49,939		409.0	%

Oil:
Sales Volume (MMcfe)	510			414		96			23.2	%
Sales Volume (Mbbls)	85			69		16			23.2	%
Gross Price ($/Bbl)	$	91.92		$	87.42	$	4.50		5.1	%
Gross Revenue	$	7,808		$	6,034	$	1,774		29.4	%

Condensate:
Sales Volume (MMcfe)	1,591			187		1,404			750.8	%
Sales Volume (Mbbls)	265			31		234			754.8	%
Gross Price ($/Bbl)	$	86.76		$	85.50	$	1.26		1.5	%
Gross Revenue	$	23,004		$	2,663	$	20,341		763.8	%

GAS
Sales Volume (MMcf)	154,267			121,793		32,474			26.7	%
Sales Price ($/Mcf)	$	4.30		$	3.75	$	0.55		14.7	%
Hedging Impact ($/Mcf)	$	(0.01	)	$	0.46	$	(0.47	)	(102.2	)%
Gross Revenue including Hedging Impact	$	662,376		$	513,316	$	149,060		29.0	%

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



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Average Sales Price (per Mcfe)	$	4.57	$	4.31	$	0.26		6.0	%
Average Costs (per Mcfe)	3.37		3.49		(0.12		)	(3.4	)%
Margin	$	1.20	$	0.82	$	0.38		46.3	%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $755 million for the nine months ended September 30, 2014 compared to $534 million for the nine months ended September 30, 2013. The increase was primarily due to the 33.3% increase in total volumes sold, along with a 6.0% increase in average price per Mcfe. The increase in average sales price is the result of a $0.55 per Mcfe increase in general market prices and the $0.18 per Mcfe increase in sales of NGLs, oil and condensate. The increase was offset, in part, by the $0.47 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 118.2 Bcf of our produced gas sales volumes for the nine months ended September 30, 2014 at an average loss of $0.01 per Mcf. These financial hedges represented approximately 60.3 Bcf of our produced gas sales volumes for the nine months ended September 30, 2013 at an average gain of $0.94 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 33.3% increase in volumes in the period-to-period comparison and the shift to lower cost Marcellus production. Marcellus production made up 45.5% of gas sales volume for the nine months ended September 30, 2014 compared to 31.0% in the nine months ended September 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 $279 million of earnings before income tax for the nine months ended September 30, 2014 compared to $270 million for the nine months ended September 30, 2013. The total coal division sold 24.3 million tons of coal produced from CONSOL Energy mines for the nine months ended September 30, 2014 compared to 21.6 million tons for the nine months ended September 30, 2013. Current period sales tons were comprised of 83% thermal and 17% metallurgical. Prior period sales tons were comprised of 74% thermal and 26% metallurgical.

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



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Average Sales Price per ton sold	$	63.64	$	70.17	$	(6.53	)	(9.3	)%
Average Costs of Goods Sold per ton	47.55		51.03		(3.48		)	(6.8	)%
Margin	$	16.09	$	19.14	$	(3.05	)	(15.9	)%

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 4.7 million tons on the export market at an average sales price of $64.24 per ton for the nine months ended September 30, 2014 compared to 6.0 million tons at an average price of $74.04 per ton for the nine months ended September 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. Average cost of goods sold was also impacted by the decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. The decrease was offset, in part, by geoglogical conditions at Enlow Fork Mine.

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



	For the Nine Months Ended September 30,
(in millions)	2014		2013		Variance			Percent Change
Continuing Operations General and Administrative Expenses	$	82	$	58	$	24		41.4	%
Discontinued Operations General and Administrative Expenses	—		31		(31		)	(100.0	)%
Total Company General and Administrative Expense	$	82	$	89	$	(7	)	(7.9	)%

Overall, total Company General and Administrative Expenses decreased $7 million in the period-to-period comparison. This was primarily due to reduced staffing and cost control projects following the December 2013 sale of five of our West Virginia coal mines. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.

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 $116 million for the nine months ended September 30, 2014 compared to $127 million for the nine months ended September 30, 2013. The decrease of $11 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in $25 million of expense during nine months ended September 30, 2014 compared to $38 million of expense in nine months ended September 30, 2013. Pension settlement accounting 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. Not included in the long-term liability expense totals discussed above are curtailment gains of $36 million, and $46 million of expense for cash payments made to active employees both of which arose from modifications to the OPEB and Pension plans during the nine months ended September 30, 2014. The pension settlement expense, cash payments and curtailment gains were not allocated to individual operating segments and are therefore not included in unit costs presented for the E&P or Coal divisions. 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.

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

The E&P segment contributed $139 million to earnings before income tax for the nine months ended September 30, 2014 compared to a loss before income tax of $7 million in the nine months ended September 30, 2013. Variances by the individual E&P segments are discussed below.



	For the Nine Months Ended												Difference to Nine Months Ended
	September 30, 2014												September 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	$	339	$	259	$	84		$	70		$	752	$	172	$	4		$	(15	)	$	59		$	220
Related Party	—		3		—			—			3		—		1			—			—			1
Total Outside Sales	339		262		84			70			755		172		5			(15		)	59			221
Gas Royalty Interest	—		—		—			63			63		—		—			—			16			16
Purchased Gas	—		—		—			6			6		—		—			—			2			2
Other Income	—		—		—			63			63		—		—			—			26			26
Total Revenue and Other Income	339		262		84			202			887		172		5			(15		)	103			265
Lifting	19		28		27			12			86		5		1			1			9			16
Ad Valorem, Severance, and Other Taxes	11		9		6			3			29		5		2			(2		)	3			8
Gathering	71		79		22			8			180		41		(6		)	(4		)	5			36
E&P Direct Administrative, Selling & Other	26		8		3			2			39		7		2			(4		)	(1		)	4
Depreciation, Depletion and Amortization	91		67		42			26			226		46		(1		)	(2		)	18			61
General & Administration	—		—		—			48			48		—		—			—			19			19
Gas Royalty Interest	—		—		—			53			53		—		—			—			15			15
Purchased Gas	—		—		—			5			5		—		—			—			2			2
Exploration and Other Costs	—		—		—			15			15		—		—			—			(29		)	(29		)
Other Corporate Expenses	—		—		—			61			61		—		—			—			(13		)	(13		)
Interest Expense	—		—		—			6			6		—		—			—			—			—
Total Cost	218		191		100			239			748		104		(2		)	(11		)	28			119
Earnings Before Income Tax	$	121	$	71	$	(16	)	$	(37	)	$	139	$	68	$	7		$	(4	)	$	75		$	146

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $121 million to the total Company earnings before income tax for the nine months ended September 30, 2014 compared to $53 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Marcellus Gas - Gas Sales Volumes (Bcf)	68.3		36.8		31.5			85.6	%
NGLs Sales Volumes (Bcfe)*	6.2		1.5		4.7			313.3	%
Condensate Sales Volumes (Bcfe)*	0.7		0.2		0.5			250.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	75.2		38.5		36.7			95.3	%

Average Sales Price - Gas (Mcf)	$	4.16	$	3.79	$	0.37		9.8	%
Hedging Impact - Gas (Mcf)	$	0.04	$	0.37	$	(0.33	)	(89.2	)%
Average Sales Price - NGLs (Mcfe)*	$	6.93	$	8.14	$	(1.21	)	(14.9	)%
Average Sales Price - Condensate (Mcfe)*	$	13.72	$	14.55	$	(0.83	)	(5.7	)%

Total Average Marcellus sales (per Mcfe)	$	4.51	$	4.35	$	0.16		3.7	%
Average Marcellus lifting costs (per Mcfe)	$	0.25	$	0.38	$	(0.13	)	(34.2	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.16	$	0.15	$	0.01		6.7	%
Average Marcellus gathering costs (per Mcfe)	$	0.95	$	0.79	$	0.16		20.3	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.34	$	0.48	$	(0.14	)	(29.2	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.20	$	1.16	$	0.04		3.4	%
Total Average Marcellus costs (per Mcfe)	$	2.90	$	2.96	$	(0.06	)	(2.0	)%
Average Margin for Marcellus (per Mcfe)	$	1.61	$	1.39	$	0.22		15.8	%

The Marcellus segment sales revenues were $339 million for the nine months ended September 30, 2014 compared to $167 million for the nine months ended September 30, 2013. The $172 million increase is primarily due to a 95.3% increase in total volumes sold, and a 3.7% increase in total average sales prices in the period-to-period comparison. The 36.7 Bcfe increase in sales volumes is primarily due to additional wells coming online from our ongoing drilling program. The $0.16 per Mcfe increase in Marcellus total average sales price was primarily the result of the $0.37 per Mcf increase in gas market prices, along with an uplift from an additional 5.2 Bcfe, or $0.12 per Mcfe, of NGLs and condensate sales volumes. The increase was offset, in part, by a $0.33 per Mcf decrease resulting from various transactions relating to our hedging program. These financial hedges represented approximately 50.3 Bcf of our produced Marcellus gas sales volumes for the nine months ended September 30, 2014 at an average gain of $0.05 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 15.2 Bcf at an average gain of $0.90 per Mcf.

Total costs for the Marcellus segment were $218 million for the nine months ended September 30, 2014 compared to $114 million for the nine months ended September 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 $19 million for the nine months ended September 30, 2014 compared to $14 million for the nine months ended September 30, 2013. The increase in total dollars primarily relates to 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 $11 million for the nine months ended September 30, 2014 compared to $6 million for the nine months ended September 30, 2013. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by the 9.8% 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 $71 million for the nine months ended September 30, 2014 compared to $30 million for the nine months ended September 30, 2013. Total dollars increased primarily due to the 95.3% increase in sales volumes which resulted in an increase in related party gathering fees, increased processing fees associated with NGLs, and an increase in utilized firm transportation expense. The impact on unit costs due to the increase in total dollars was offset, in part, by the increase in sales volumes.

•Marcellus direct administrative, selling and other costs were $26 million for the nine months ended September 30, 2014 compared to $19 million for the nine months ended September 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 $91 million for the nine months ended September 30, 2014 compared to $45 million for the nine months ended September 30, 2013. There was approximately $89 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 in the nine months ended September 30, 2014. There was approximately $44 million, or $1.15 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2013. There was approximately $2 million, or $0.01 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the nine months ended September 30, 2014. There was $1 million, or $0.01 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for for the nine months ended September 30, 2013.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $71 million to the total Company earnings before income tax for the nine months ended September 30, 2014 compared to $64 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
	2014			2013		Variance			Percent Change
CBM Gas - Gas Sales Volumes (Bcf)	59.5			62.6		(3.1		)	(5.0	)%

Average Sales Price - Gas (Mcf)	$	4.47		$	3.71	$	0.76		20.5	%
Hedging Impact - Gas (Mcf)	$	(0.07	)	$	0.40	$	(0.47	)	(117.5	)%

Total Average CBM sales price (per Mcf)	$	4.40		$	4.11	$	0.29		7.1	%
Average CBM lifting costs (per Mcf)	$	0.47		$	0.44	$	0.03		6.8	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.16		$	0.10	$	0.06		60.0	%
Average CBM gathering costs (per Mcf)	$	1.33		$	1.37	$	(0.04	)	(2.9	)%
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)	$	1.11		$	1.07	$	0.04		3.7	%
Total Average CBM costs (per Mcf)	$	3.20		$	3.08	$	0.12		3.9	%
Average Margin for CBM (per Mcf)	$	1.20		$	1.03	$	0.17		16.5	%

CBM sales revenues were $262 million in the nine months ended September 30, 2014 compared to $257 million for the nine months ended September 30, 2013. The $5 million increase was primarily due to a 7.1% increase in total average sales price offset, in part, by a 5.0% decrease in total volumes sold. CBM sales volumes decreased 3.1 Bcf for the nine months ended September 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 the Company's current focus is on Marcellus production. The decline in wells drilled is also due to the decline in coal production at our Buchanan Mine which resulted in fewer GOB collection wells being drilled. The CBM total average sales price increased $0.29 per Mcf due to a $0.76 per Mcf increase in market prices. The increase was offset, in part, by a $0.47 per Mcf decrease resulting from various transactions relating to our hedging program. Financial hedges represented approximately 53.0 Bcf of our produced CBM gas sales volumes for the nine months ended

September 30, 2014 at an average loss of $0.08 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 34.4 Bcf at an average gain of $0.73 per Mcf.

Total costs for the CBM segment were $191 million for the nine months ended September 30, 2014 compared to $193 million for the nine months ended September 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 $28 million for the nine months ended September 30, 2014 compared to $27 million for the nine months ended September 30, 2013. The increase in total dollars was primarily due to an increase in well servicing costs. The increase in unit costs was primarily due to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $9 million for the nine months ended September 30, 2014 compared to $7 million for the nine months ended September 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 $79 million for the nine months ended September 30, 2014 compared to $85 million for the nine months ended September 30, 2013. The decrease in total dollars and average per unit costs is due to lower utilized firm transportation expenses resulting from the decrease in gas sales volumes. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $8 million for the nine months ended September 30, 2014 compared to $6 million for the nine months ended September 30, 2013. The $2 million increase in the period-to-period comparison was due to CBM volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $67 million for the nine months ended September 30, 2014 and $68 million for the nine months ended September 30, 2013. There was approximately $45 million, or $0.75 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the nine months ended September 30, 2014. The production portion of depreciation, depletion and amortization was $47 million, or $0.74 per unit-of-production in the nine months ended September 30, 2013. There was approximately $22 million, or $0.36 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the nine months ended September 30, 2014. The non-production related depreciation, depletion and amortization was $21 million, or $0.33 per Mcf for the nine months ended September 30, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $16 million for the nine months ended September 30, 2014 compared to a loss before income tax of $12 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
	2014			2013			Variance			Percent Change
Shallow Oil and Gas - Gas Sales Volumes (Bcf)	18.1			20.3			(2.2		)	(10.8	)%
Oil Sales Volumes (Bcfe)*	0.3			0.3			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	18.4			20.6			(2.2		)	(10.7	)%

Average Sales Price - Gas (Mcf)	$	4.37		$	3.80		$	0.57		15.0	%
Hedging Impact - Gas (Mcf)	$	0.02		$	0.87		$	(0.85	)	(97.7	)%
Average Sales Price - Oil (Mcfe)*	$	15.02		$	13.55		$	1.47		10.8	%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	4.59		$	4.81		$	(0.22	)	(4.6	)%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.47		$	1.27		$	0.20		15.7	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)	$	0.31		$	0.36		$	(0.05	)	(13.9	)%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.21		$	1.26		$	(0.05	)	(4.0	)%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.19		$	0.34		$	(0.15	)	(44.1	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.29		$	2.15		$	0.14		6.5	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.47		$	5.38		$	0.09		1.7	%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.88	)	$	(0.57	)	$	(0.31	)	(54.4	)%

Shallow Oil and Gas sales revenues were $84 million for the nine months ended September 30, 2014 compared to $99 million for the nine months ended September 30, 2013. The $15 million decrease is the result of a 10.7% decrease in total volumes sold and a 4.6% decrease 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 decrease in shallow oil and gas total average sales price was primarily the result of an $0.85 per Mcf decrease resulting from various transactions relating to our hedging program offset by a $0.57 per Mcf increase in average gas market prices. These financial hedges represented approximately 11.4 Bcf of our produced shallow oil and gas sales volumes for the nine months ended September 30, 2014 at an average gain of $0.03 per Mcf. For the nine months ended September 30, 2013, these financial hedges represented approximately 10.6 Bcf at an average gain of $1.67 per Mcf.

Total costs for the shallow oil and gas segment were $100 million for the nine months ended September 30, 2014 compared to $111 million for the nine months ended September 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 $27 million for the nine months ended September 30, 2014 compared to $26 million for the nine months ended September 30, 2013. The $1 million increase in total dollars is primarily due to an increase in environmental compliance, well servicing costs, and general well site maintenance expenses offset, in part, by a decrease in road maintenance expense. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes were $6 million for the nine months ended September 30, 2014 compared to $8 million for the nine months ended September 30, 2013. The $2 million decease in total dollars is primarily due to decrease in gas sales volumes offset, in part, by the increase in average gas sales prices, without the impact of hedging. The improvement in unit costs was offset, in part, by the decrease in gas sales volumes.

•Shallow Oil and Gas gathering costs were $22 million for the nine months ended September 30, 2014 compared to $26 million for the nine months ended September 30, 2013. Gathering costs decreased $4 million primarily due to a decrease in

both interruptible gathering and utilized firm transportation expenses in the period-to-period comparison. The decrease in total dollars was partially offset by the decrease in gas sales volumes.

•Shallow Oil and Gas direct administrative, selling and other costs were $3 million for the nine months ended September 30, 2014 compared to $7 million for the nine months ended September 30, 2013. The $4 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 partially offset by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $42 million for the nine months ended September 30, 2014 compared to $44 million for the nine months ended September 30, 2013. There was approximately $37 million, or $2.00 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2014. There was approximately $39 million, or $1.90 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the nine months ended September 30, 2013. There was approximately $5 million, or $0.29 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the nine months ended September 30, 2014. There was $5 million, or $0.25 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the nine months ended September 30, 2013.

OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the Utica Shale and the Chattanooga Shale in Tennessee. Revenue from Utica Shale operations was approximately $56 million for the nine months ended September 30, 2014 compared to $2 million for the nine months ended September 30, 2013. Revenue from other Shale operations was $14 million for the nine months ended September 30, 2014 compared to $9 million for the nine months ended September 30, 2013. Total costs related to Utica Shale operations were $31 million for the nine months ended September 30, 2014 compared to $3 million for the nine months ended September 30, 2013. Total costs related to other Shale operations were $20 million for the nine months ended September 30, 2014 compared to $14 million for the nine months ended September 30, 2013. A per unit analysis of the other operating costs in the Utica Shale and 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 $63 million for the nine months ended September 30, 2014 compared to $47 million for the nine months ended September 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 Nine Months Ended September 30,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	14.6		10.9		3.7		33.9	%
Average Sales Price Per thousand cubic feet	$	4.30	$	4.27	$	0.03	0.7	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $6 million for the nine months ended September 30, 2014 compared to $4 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
	2014		2013		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	1.1		1.1		—		—	%
Average Sales Price Per thousand cubic feet	$	5.72	$	4.12	$	1.60	38.8	%

Other income was $63 million for the nine months ended September 30, 2014 compared to $37 million for the nine months ended September 30, 2013. The $26 million increase was primarily due to the following items:


•	Other income increased $19 million primarily due to an increase in revenue related to certain gathering arrangements.


•	Earnings from our equity affiliates increased $13 million primarily due to an increase in earnings from CONE Gathering LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.


•	Interest income decreased $13 million due to the scheduled collection of the final installment in 2013 on the notes receivable from the 2011 Noble Energy joint venture transaction.


•	Gain on property sales increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	The remaining $3 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 $48 million for the nine months ended September 30, 2014 compared to $29 million for the nine months ended September 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 $53 million for the nine months ended September 30, 2014 compared to $38 million for the nine months ended September 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 Nine Months Ended September 30,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	14.6		10.9		3.7		33.9	%
Average Cost Per thousand cubic feet sold	$	3.68	$	3.50	$	0.18	5.1	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $5 million for the nine months ended September 30, 2014 compared to $3 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
	2014		2013		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	1.1		1.1		—		—	%
Average Cost Per thousand cubic feet sold	$	4.63	$	2.79	$	1.84	65.9	%

Exploration and other costs were $15 million for the nine months ended September 30, 2014 compared to $44 million for the nine months ended September 30, 2013. The $29 million decrease is due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2014		2013		Variance			Percent Change
Marcellus Title Defects	$	—	$	22	$	(22	)	(100.0	)%
Lease Expiration Costs	5		6		(1		)	(16.7	)%
Land Rentals	4		5		(1		)	(20.0	)%
Seismic Activity	3		3		—			—	%
Other	3		8		(5		)	(62.5	)%
Total Exploration and Other Costs	$	15	$	44	$	(29	)	(65.9	)%


•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $22 million for the nine months ended September 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.


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


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

Other corporate expenses were $61 million for the nine months ended September 30, 2014 compared to $74 million for the nine months ended September 30, 2013. Other corporate expense was made up of the following items:



	For the Nine Months Ended September 30,
(in millions)	2014			2013		Variance			Percent Change
Litigation Settlements	$	(5	)	$	2	$	(7	)	(350.0	)%
Stock-based Compensation	13			19		(6		)	(31.6	)%
Short-term Incentive Compensation	15			16		(1		)	(6.3	)%
Bank Fees	4			5		(1		)	(20.0	)%
Unutilized Firm Transportation and Processing Fees	29			28		1			3.6	%
Other	5			4		1			25.0	%
Total Other Corporate Expenses	$	61		$	74	$	(13	)	(17.6	)%


•	Litigation settlements decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.


•	Stock-based compensation decreased $6 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.


•	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, compliance and unit costs. Short term incentive compensation expense decreased $1 million in the period-to-period comparison due to lower projected payouts.


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


•	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 $1 million increase is primarily due to increased firm transportation capacity which has not been utilized by active operations.


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

Interest expense related to the gas segment remained consistent at $6 million for the nine months ended September 30, 2014 and September 30, 2013.

TOTAL COAL SEGMENT ANALYSIS for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:

The coal segment contributed $279 million of earnings before income tax in the nine months ended September 30, 2014 compared to $270 million in the nine months ended September 30, 2013. Variances by the individual coal segments are discussed below.



	For the Nine Months Ended														Difference to Nine Months Ended
	September 30, 2014														September 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	$	1,263		$	64	$	221		$	—		$	1,548		$	229		$	(61	)	$	(135	)	$	—		$	33
Purchased Coal	—			—		—			8			8			—			—			—			(9		)	(9		)
Total Outside Sales	1,263			64		221			8			1,556			229			(61		)	(135		)	(9		)	24
Freight Revenue	—			—		—			23			23			—			—			—			(8		)	(8		)
Other Income	—			6		—			100			106			(2		)	4			—			16			18
Total Revenue and Other Income	1,263			70		221			131			1,685			227			(57		)	(135		)	(1		)	34
Costs and Expenses:
Beginning inventory costs	21			—		11			—			32			(12		)	—			(10		)	—			(22		)
Total direct operating costs	586			29		113			102			830			116			(34		)	(34		)	10			58
Total royalty/production taxes	59			3		13			1			76			5			—			(7		)	—			(2		)
Total direct services to operations	91			4		17			87			199			(5		)	(7		)	(1		)	(20		)	(33		)
Total retirement and disability	64			3		15			2			84			19			(3		)	(4		)	(7		)	5
Depreciation, depletion and amortization	117			6		29			34			186			28			(6		)	(2		)	(4		)	16
Ending inventory costs	(17		)	—		(7		)	—			(24		)	11			—			—			—			11
Total Costs and Expenses	921			45		191			226			1,383			162			(50		)	(58		)	(21		)	33
Freight Expense	—			—		—			23			23			—			—			—			(8		)	(8		)
Total Costs	921			45		191			249			1,406			162			(50		)	(58		)	(29		)	25
Earnings (Loss) Before Income Taxes	$	342		$	25	$	30		$	(118	)	$	279		$	65		$	(7	)	$	(77	)	$	28		$	9

THERMAL COAL SEGMENT

The thermal coal segment contributed $342 million to total Company earnings before income tax for the nine months ended September 30, 2014 compared to $277 million for the nine months ended September 30, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	20.2		15.9		4.3			27.0	%
Average Sales Price Per Thermal Ton Sold	$	62.38	$	64.82	$	(2.44	)	(3.8	)%

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

Total Direct Operating Costs Per Thermal Ton Produced	$	28.98	$	29.62	$	(0.64	)	(2.2	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	2.93		3.41		(0.48		)	(14.1	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.52		6.08		(1.56		)	(25.7	)%
Total Retirement and Disability Per Thermal Ton Produced	3.18		2.84		0.34			12.0	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.77		5.63		0.14			2.5	%
Total Production Costs Per Thermal Ton Produced	$	45.38	$	47.58	$	(2.20	)	(4.6	)%

Ending Inventory Costs Per Thermal Ton	$	48.22	$	53.04	$	(4.82	)	(9.1	)%

Total Costs Per Thermal Ton Sold	$	45.43	$	47.53	$	(2.10	)	(4.4	)%
Average Margin Per Thermal Ton Sold	$	16.95	$	17.29	$	(0.34	)	(2.0	)%

Thermal coal outside sales revenue was $1,263 million for the nine months ended September 30, 2014 compared to $1,034 million for the nine months ended September 30, 2013. The $229 million increase was attributable to a 4.3 million increase in tons sold offset, in part, by a $2.44 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 1.4 million tons of thermal coal being priced on the export market at an average sales price of $67.18 per ton for the nine months ended September 30, 2014 compared to 1.4 million tons at an average price of $63.32 per ton for the nine months ended September 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 $921 million for the nine months ended September 30, 2014, or $162 million higher than the $759 million for the nine months ended September 30, 2013. Total cost of goods sold for thermal coal was $45.43 per ton in the nine months ended September 30, 2014 compared to $47.53 per ton in the nine months ended September 30, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 27.0% 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 an additional longwall overhaul, a belt repair project, and 32k additional continuous miner footage. The additional continuous miner footage resulted in additional roof support, haulage, and mine maintenance costs. Unit costs were also negatively 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 $25 million to total Company earnings before income tax for the nine months ended September 30, 2014 compared to $32 million for the nine months ended September 30, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	1.1		1.9		(0.8		)	(42.1	)%
Average Sales Price Per High Vol Met Ton Sold	$	60.99	$	64.84	$	(3.85	)	(5.9	)%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	27.30	$	32.10	$	(4.80	)	(15.0	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	2.95		1.66		1.29			77.7	%
Total Direct Services to Operations Per High Vol Met Ton Produced	4.11		5.97		(1.86		)	(31.2	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.10		3.11		(0.01		)	(0.3	)%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.78		6.10		(0.32		)	(5.2	)%
Total Production Costs Per High Vol Met Ton Produced	$	43.24	$	48.94	$	(5.70	)	(11.6	)%

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

Total Costs Per High Vol Met Ton Sold	$	43.24	$	48.94	$	(5.70	)	(11.6	)%
Margin Per High Vol Met Ton Sold	$	17.75	$	15.90	$	1.85		11.6	%

High volatile metallurgical coal outside sales revenue was $64 million for the nine months ended September 30, 2014 compared to $125 million for the nine months ended September 30, 2013. The $61 million decrease was primarily due to the 0.8 million decrease in sales tons along with the $3.85 per ton decrease in average sales price. The decrease in sales price was due to 1.1 million tons of high volatile metallurgical coal being sold on the export market at an average sales price of $60.94 per ton for the nine months ended September 30, 2014 compared to 1.7 million tons at an average price of $62.70 per ton for the nine months ended September 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 $45 million for the nine months ended September 30, 2014, or $50 million lower than the $95 million for the nine months ended September 30, 2013. Total cost of goods sold for high volatile metallurgical coal was $43.24 per ton in the nine months ended September 30, 2014 compared to $48.94 per ton in the nine months ended September 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 $30 million to total Company earnings before income tax in the nine months ended September 30, 2014 compared to $107 million in the nine months ended September 30, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Nine Months Ended September 30,
	2014		2013		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	3.0		3.7		(0.7		)	(18.9	)%
Average Sales Price Per Low Vol Met Ton Sold	$	72.94	$	95.89	$	(22.95	)	(23.9	)%

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	$	37.67	$	41.00	$	(3.33	)	(8.1	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	4.46		5.59		(1.13		)	(20.2	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.57		5.11		0.46			9.0	%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.19		5.43		(0.24		)	(4.4	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	9.58		8.64		0.94			10.9	%
Total Production Costs Per Low Vol Met Ton Produced	$	62.47	$	65.77	$	(3.30	)	(5.0	)%

Ending Inventory Costs Per Low Vol Met Ton	$	52.53	$	65.42	$	(12.89	)	(19.7	)%

Total Costs Per Low Vol Met Ton Sold	$	63.10	$	67.12	$	(4.02	)	(6.0	)%
Margin Per Low Vol Met Ton Sold	$	9.84	$	28.77	$	(18.93	)	(65.8	)%

Low volatile metallurgical coal outside sales revenue was $221 million for the nine months ended September 30, 2014 compared to $356 million for the nine months ended September 30, 2013. The $135 million decrease was attributable to a $22.95 per ton lower average sales price and a 0.7 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.

Total cost of goods sold for low volatile metallurgical coal was $191 million for the nine months ended September 30, 2014, or $58 million lower than the $249 million for the nine months ended September 30, 2013. Total cost of goods sold for low volatile metallurgical coal was $63.10 per ton in the nine months ended September 30, 2014 compared to $67.12 per ton in the nine months ended September 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 a reduction in the number of degas wells drilled. The decreases were related to lower average sales prices and cost control measures that were implemented due to the weak metallurgical coal market. Part of the cost control measures included a decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014. These improvements were offset, in part, by lower tons sold.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $118 million for the nine months ended September 30, 2014 compared to a loss before income tax of $146 million for the nine months ended September 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 $8 million for the nine months ended September 30, 2014 compared to $17 million for the nine months ended September 30, 2013. The decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

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 $23 million for the nine months ended September 30, 2014 compared to $31 million for the nine months ended September 30, 2013. The $8 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $100 million for the nine months ended September 30, 2014 compared to $84 million for the nine months ended September 30, 2013. The change is due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2014		2013		Variance
Rental Income	$	35	$	2	$	33
Coal Contract Buyout	30		—		30
Equity in earnings of affiliates	11		7		4
Royalty Income	15		13		2
Business Interruption Proceeds - Bailey Mine	—		5		(5		)
Gain on Sale of Assets	1		45		(44		)
Other	14		12		2
Total Other Income Coal Segment	$	106	$	84	$	22


•	Rental income increased $33 million due to equipment subleased to a third-party. These arrangements began in December 2013.


•	For the nine months ended September 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 nine months ended September 30, 2013.


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


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


•	Business interruption proceeds of $5 million were received in the prior year-to-date period related to the 2012 Bailey Belt Conveyor accident.


•	Gain on sale of assets decreased $44 million primarily due to the sale of Potomac coal reserves, as well as the sale of a 50% interest in a joint venture in Alberta, Canada in the nine months ended September 30, 2013. No such transactions were entered into in the nine months ended September 30, 2014.


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

Other coal segment total costs were $249 million for the nine months ended September 30, 2014 compared to $278 million for the nine months ended September 30, 2013. The decrease of $29 million was primarily due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2014		2013		Variance
Closed and Idle Mines	$	62	$	85	$	(23	)
Purchased Coal	13		32		(19		)
Freight Expense	23		31		(8		)
Stock-based and Incentive Compensation	41		43		(2		)
Depreciation, Depletion, and Amortization	19		21		(2		)
General and Administrative Expense	33		28		5
Lease Rental Expense	23		1		22
Other	35		37		(2		)
Total Other Coal Segment Costs	$	249	$	278	$	(29	)

•

Closed and idle mine costs decreased approximately $23 million for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. This was due to a $14 million decrease in the asset retirement obligation, primarily at the Fola Mining Complex. The remaining $9 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 $19 million due to lower volumes of coal that needed to be purchased to fulfill various contracts.

•


•	Stock-based and Incentive Compensation decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.


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


•	General and Administrative Expense related to the other coal segment increased by $5 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.


•	Lease rental expense increased $22 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 decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the nine months ended September 30, 2014 compared to the nine months ended September 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 $314 million for the nine months ended September 30, 2014 compared to a loss before income tax of $233 million for the nine months ended September 30, 2013. The other segment also includes total Company income tax expense of $8 million for the nine months ended September 30, 2014 compared to an income tax expense of $98 million for the nine months ended September 30, 2013.



	For the Nine Months Ended September 30,
(in millions)	2014			2013			Variance			Percent Change
Sales—Outside	$	213		$	198		$	15		7.6	%
Other Income	6			5			1			20.0	%
Total Revenue	219			203			16			7.9	%
Cost of Goods Sold and Other Charges	269			274			(5		)	(1.8	)%
Depreciation, Depletion & Amortization	4			4			—			—	%
Loss on Debt Extinguishment	95			—			95			100.0	%
Interest Expense	165			158			7			4.4	%
Total Costs	533			436			97			22.2	%
Loss Before Income Tax	(314		)	(233		)	(81		)	34.8	%
Income Tax	8			98			(90		)	(91.8	)%
Net Loss	$	(322	)	$	(331	)	$	9		(2.7	)%

Industrial supplies:

Outside Sales from industrial supplies were $184 million for the nine months ended September 30, 2014 compared to $162 million for the nine months ended September 30, 2013. The increase of $22 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $180 million for the nine months ended September 30, 2014 compared to $159 million for the nine months ended September 30, 2013. The increase of $21 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 $29 million for the nine months ended September 30, 2014 compared to $36 million for the nine months ended September 30, 2013. The decrease of $7 million was primarily attributable to decreased thru-put volumes for the current year.

Total costs related to terminal activity were $20 million for the nine months ended September 30, 2014 compared to $25 million for the nine months ended September 30, 2013. Costs decreased $5 million due to decreased thru-put volumes for the current year.

Miscellaneous other:

Additional other income of $6 million was recognized for the nine months ended September 30, 2014 compared to $5 million for the nine months ended September 30, 2013. The $1 million decrease was due to various items that occurred throughout both periods, none of which were individually material.

Other corporate costs were $333 million for the nine months ended September 30, 2014 compared to $252 million for the nine months ended September 30, 2013. Other corporate costs increased due to the following items:



	For the Nine Months Ended September 30,
(in millions)	2014		2013		Variance
Loss On Debt Extinguishment	$	95	$	—	$	95
Long-Term Liability Plan Changes	10		—		10
Interest Expense	165		158		7
Revolver Modification Fees	3		—		3
Bank Fees	12		11		1
Corporate Initiative Fees and Other Legal Charges	6		12		(6		)
Pension Settlement	26		38		(12		)
CNX Gas Shareholder Settlement	—		20		(20		)
Other	16		13		3
	$	333	252		$	81

•

Loss on Debt Extinguishment of $95 million was recognized in the nine months ended September 30, 2014 related to the early extinguishment of debt due to the purchase of all the 8.00% senior notes that were due in 2017 at an average premium of 1.04%, and the partial purchase of the 8.25% senior notes that were due in 2020 at an average premium of 1.075%. No such transactions occurred in the prior period.


•	Long-Term Liability Plan Changes include $36 million of income as a result of measurements associated with amendments to the pension and OPEB plans, which were adopted during the third quarter, offset by $46 million of expense for cash payments made to active employees related to changes in the OPEB plan.

•

Interest expense increased $7 million primarily due to the decrease in capitalized interest related to the Harvey Mine going into production in 2014. 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 Unaudited Consolidated Financial Statements of this Form 10-Q), the early payoff of the 2017 bonds and partial purchase of the 2020 bonds. The decease in interest expense also related to the additional bonds, due 2022, issued in April 2014 and August 2014 which have a lower interest rate than the 2017 and the 2020 bonds.


•	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.

•

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

•

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.

•

The CNX Gas 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 shares 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 increased $3 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 8.3% for the nine months ended September 30, 2014 compared to 323.0% for the nine months ended September 30, 2013. The effective rates for the nine months ended September 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 nine months ended September 30, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. That resulted in a benefit of $8 million related to increased percentage of depletion deductions, offset, in part, by $1 million of tax expense due to changes in the Domestic Production Activities Deduction. Also, the Internal Revenue Service issued its audit report relating to the examination of CONSOL Energy’s 2008

and 2009 U.S. income tax returns during the nine months ended September 30, 2014. The result of these findings was a change in timing of certain tax deductions which increased the tax benefit of percentage of depletion by $7 million. Also, as a result of closing the IRS audit, CONSOL Energy was required to file amended state income tax returns. The company filed the required amended returns and realized a discrete state income tax charge of $5 million which was offset by a federal income tax benefit of $2 million. See Note 6 - Income Taxes of the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Nine Months Ended September 30,
(in millions)	2014			2013			Variance			Percent Change
Total Company Earnings Before Income Tax	$	103		$	30		$	73		(242.5	)%
Income Tax Expense	$	8		$	98		$	(90	)	(91.5	)%
Effective Income Tax Rate	8.3		%	323.0		%	(314.7		)%

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 its 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 5.26 to 1.00 at September 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 2.33 to 1.00 at September 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 September 30, 2014, the facility had no outstanding borrowings and $265 million of letters of credit outstanding, leaving $1,735 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 September 30, 2014, eligible accounts receivable totaled approximately $83 million. At September 30, 2014, the facility had no outstanding borrowings and $62 million of letters of credit outstanding, leaving $21 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 $43 million at September 30, 2014. The ineffective portion of these contracts was $2.7 million during the nine months ended September 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 Nine Months Ended September 30,
	2014			2013			Change
Cash Flows from Operating Activities	$	850		$	589		$	261
Cash Used in Investing Activities	$	(925	)	$	(559	)	$	(366	)
Cash (Used in) Provided by Financing Activities	$	(27	)	$	(30	)	$	3

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


•	Net income increased $168 million in the period-to-period comparison.


•	Adjustments to reconcile net income to cash flow provided by operating activities increased $95 million due to the loss on extinguishment of debt, $38 million from the return on the equity in earnings, and additional depreciation, depletion and amortization of $77 million.


•	Return on equity investments of $47 million was related to IPO proceeds received from CONE Midstream Partners, LP.


•	Income tax refunds of $71 million, net of payments, in the nine months ended September 30, 2014 compared to $46 million of payments in the nine months ended September 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 $154 million in the period-to-period comparison due to:


◦	Gas segment capital expenditures increased $183 million. The increase was comprised of increased drilling and completions activity in the Marcellus and Utica plays and various other individually insignificant projects. The increase was partially offset by $174 million of carry received from our JV Partners.


◦	Coal segment capital expenditures decreased $2 million. This was comprised of an increase of $57 million for the acquisition of the Harvey Mine longwall shields, offset by a decrease of $22 million related to the Enlow Fork Overland Belt Project, which was completed in February 2014 and a decrease of $37 million in various other projects, none of which were material; and


◦	Other capital expenditures decreased $27 million due to a decrease in capitalized interest of $9 million related to the completion of the Harvey Mine capital project and a decrease of $18 million related to various other transactions that occurred throughout the nine months ended September 30, 2014, none of which were individually material.


•	Proceeds from the sale of assets, continuing operations, increased $4 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;


◦	$25 million received in August 2013 related to the sale of the Crowsnest Pass.

(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 $127 million primarily due to a $157 million increase on the return of investment from the IPO of CONE Midstream Partners, LP, offset by $30 million of additional capital contributions to CONE in 2014.

•

Restricted cash decreased $56 million due to the release of the cash restrictions including $48 million associated with the Ram River & Scurry Canadian asset proceeds and $20 million associated with the Ryerson Dam Settlement. This was offset by the additional $12 million of restricted cash associated with the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada in August 2013.


•	There were no investing activities related to discontinued operations in 2014. Discontinued Operations in 2013 consisted of $175 million of capital expenditures offset by $134 million in proceeds related to two sales leasebacks of two long wall shields.

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


•	In the nine months ended September 30, 2014, CONSOL Energy repaid $4 million of miscellaneous borrowings. In the nine months ended September 30, 2013, CONSOL Energy repaid $32 million of miscellaneous borrowings.


•	In the nine months ended September 30, 2014, CONSOL Energy paid $12 million related to transaction fees in the refinancing of the revolving credit facilities, as compared to $47 million of short term borrowings received under the revolving credit facilities in the nine months ended September 30, 2013.


•	In the nine months ended September 30, 2014, CONSOL Energy received $13 million related to the issuance of common stock in its stock based compensation plans as compared to $2 million in the nine months ended September 30, 2013.


•	In 2013, CONSOL Energy received $7 million of borrowings under its Securitization Facility, there was no activity in 2014.


•	In the nine months ended September 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.

•

In the nine months ended September 30, 2014, CONSOL Energy paid three quarterly dividends totaling $43 million at an amount per share of $.0625. In the nine months ended September 30, 2013, CONSOL Energy paid only two quarterly dividends totaling $57 million at an amount per share of $.125. This was due to the accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 which resulted in no dividends paid in the first quarter of 2013.


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

The following is a summary of our significant contractual obligations at September 30, 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	$	130,669	$	175,764	$	65,408	$	16,006	$	387,847
Gas Firm Transportation and Processing	110,196		195,363		158,986		476,819		941,364
Long-Term Debt	3,558		6,712		2,619		3,226,841		3,239,730
Interest on Long-Term Debt	212,018		429,011		428,758		473,359		1,543,146
Capital (Finance) Lease Obligations	8,667		15,015		13,569		14,530		51,781
Interest on Capital (Finance) Lease Obligations	3,256		4,883		3,144		1,213		12,496
Operating Lease Obligations	104,883		183,147		99,878		83,014		470,922
Long-Term Liabilities—Employee Related (a)	88,071		184,506		187,115		479,379		939,071
Other Long-Term Liabilities (b)	328,605		194,694		85,527		356,095		964,921
Total Contractual Obligations (c)	$	989,923	$	1,389,095	$	1,045,004	$	5,127,256	$	8,551,278

_________________________

(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 fourth quarter 2014 contributions are expected to be approximately $0.5 million.


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


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

Debt

At September 30, 2014, CONSOL Energy had total long-term debt and capital lease obligations of $3.3 billion outstanding, including the current portion of long-term debt of $12.2 million. This long-term debt consisted of:


•	An aggregate principal amount of $1.02 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 $1.85 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 $52 million of capital leases with a weighted average interest rate of 6.29% per annum.

At September 30, 2014, CONSOL Energy had no outstanding borrowings and had approximately $265 million of letters of credit outstanding under its $2.0 billion senior secured revolving credit facility.

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

Total Equity and Dividends

CONSOL Energy had total equity of $5.3 billion at September 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, changes in comprehensive income, and issuance of common stock. The increase in equity was offset, in part, by payment of 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
October 29, 2014	$0.0625	November 10, 2014	December 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 2.68 to 1.00 and the cumulative credit was approximately $450 million at September 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 nine months ended September 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 September 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 September 30, 2014. Management believes these items will expire without being funded. See Note 12 - Commitments and Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Forward-Looking Statements

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


•	deterioration in 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 the 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 September 30, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $62.6 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $31.6 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At September 30, 2014, CONSOL Energy had $3.30 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 September 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 October 14, 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		N/A		41,740,578		41,740,578
Weighted Average Hedge Price per Mcf	N/A		N/A		N/A		$	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 September 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 Contingent Liabilities in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

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


ITEM 6.	EXHIBITS



4.1			Registration Rights Agreement, dated as of August 12, 2014, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Goldman, Sachs & Co. as the initial purchaser named therein, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 12, 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 September 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: November 4, 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)