Edgar Filing: CONSOL Energy Inc

CNX-3.31.15-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended March 31, 2015



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of April 17, 2015
Common stock, $0.01 par value		228,822,133

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

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

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	59

ITEM 4.	Controls and Procedures	60

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	60

ITEM 1A.	Risk Factors	60

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

ITEM 4.	Mine Safety Disclosures	64

ITEM 6.	Exhibits	65

GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMS

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

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

Bcf - One billion cubic feet of natural gas.

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

Btu - One British thermal unit.

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

Mcf - One thousand cubic feet of natural gas.

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

MMbtu - One million British Thermal units.

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

NGL - Natural gas liquids.

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

PART I : FINANCIAL INFORMATION


ITEM 1.	CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



(Dollars in thousands, except per share data)	Three Months Ended
(Unaudited)	March 31,
Revenues and Other Income:	2015			2014
Natural Gas, NGLs and Oil Sales	$	254,580		$	266,298
Unrealized Gain on Commodity Derivative Instruments	60,004			—
Coal Sales	496,666			534,681
Other Outside Sales	13,130			69,287
Gas Royalty Interests and Purchased Gas Sales	18,456			30,219
Freight-Outside Coal	6,525			9,945
Miscellaneous Other Income	38,066			55,054
Gain on Sale of Assets	2,165			3,669
Total Revenue and Other Income	889,592			969,153
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	31,612			29,243
Transportation, Gathering and Compression	78,744			53,782
Production, Ad Valorem, and Other Fees	9,192			10,187
Direct Administrative and Selling	14,667			11,653
Depreciation, Depletion and Amortization	85,104			71,729
Exploration and Production Related Other Costs	2,040			3,099
Production Royalty Interests and Purchased Gas Costs	16,127			26,096
Other Corporate Expenses	19,096			26,164
General and Administrative	15,142			17,364
Total Exploration and Production Costs	271,724			249,317
Coal Costs
Operating and Other Costs	311,583			333,810
Royalties and Production Taxes	22,317			26,488
Direct Administrative and Selling	8,983			11,542
Depreciation, Depletion and Amortization	65,483			56,866
Freight Expense	6,525			9,945
General and Administrative Costs	7,408			12,709
Other Corporate Expenses	8,895			19,295
Total Coal Costs	431,194			470,655
Other Costs
Miscellaneous Operating Expense	10,384			67,340
General and Administrative Costs	—			210
Depreciation, Depletion and Amortization	7			521
Loss on Debt Extinguishment	67,734			—
Interest Expense	55,122			50,931
Total Other Costs	133,247			119,002
Total Costs And Expenses	836,165			838,974
Earnings Before Income Tax	53,427			130,179
Income Taxes	(25,603		)	8,489
Income From Continuing Operations	79,030			121,690
Loss From Discontinued Operations, net	—			(5,687		)
Net Income	$	79,030		$	116,003

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(CONTINUED)



	Three Months Ended
(Dollars in thousands, except per share data)	March 31,
(Unaudited)	2015		2014
Earnings Per Share
Basic
Income from Continuing Operations	$	0.34	$	0.53
Loss from Discontinued Operations	—		(0.02		)
Total Basic Earnings Per Share	$	0.34	$	0.51
Dilutive
Income from Continuing Operations	$	0.34	$	0.53
Loss from Discontinued Operations	—		(0.03		)
Total Dilutive Earnings Per Share	$	0.34	$	0.50

Dividends Paid Per Share	$	0.0625	$	0.0625

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended
(Dollars in thousands)	March 31,
(Unaudited)	2015			2014
Net Income	$	79,030		$	116,003
Other Comprehensive Loss:
Actuarially Determined Long-Term Liability Adjustments (Net of tax: $90, ($2,985))	(149		)	5,119
Net Decrease in the Value of Cash Flow Hedges (Net of tax: $0, $30,856)	—			(46,965		)
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $11,213, ($10,951))	(19,314		)	16,313

Other Comprehensive Loss	(19,463		)	(25,533		)

Comprehensive Income	$	59,567		$	90,470

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands)	March 31, 2015		December 31, 2014
ASSETS
Current Assets:
Cash and Cash Equivalents	$	5,318	$	176,989
Accounts and Notes Receivable:
Trade	226,991		259,817
Other Receivables	263,490		347,146
Accounts Receivable - Securitized	32,669		—
Inventories	105,244		101,873
Deferred Income Taxes	74,725		66,569
Recoverable Income Taxes	20,566		20,401
Prepaid Expenses	203,711		193,555
Total Current Assets	932,714		1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	15,014,326		14,674,777
Less—Accumulated Depreciation, Depletion and Amortization	4,647,745		4,512,305
Total Property, Plant and Equipment—Net	10,366,581		10,162,472
Other Assets:
Investment in Affiliates	192,273		152,958
Other	289,828		277,750
Total Other Assets	482,101		430,708
TOTAL ASSETS	$	11,781,396	$	11,759,530

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands, except per share data)	March 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	532,388		$	531,973
Current Portion of Long-Term Debt	13,242			13,016
Short-Term Notes Payable	760,500			—
Borrowings Under Securitization Facility	32,669			—
Other Accrued Liabilities	569,185			602,972
Total Current Liabilities	1,907,984			1,147,961
Long-Term Debt:
Long-Term Debt	2,561,681			3,236,422
Capital Lease Obligations	38,854			39,456
Total Long-Term Debt	2,600,535			3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	304,303			325,592
Postretirement Benefits Other Than Pensions	696,327			703,680
Pneumoconiosis Benefits	117,608			116,941
Mine Closing	305,906			306,789
Gas Well Closing	178,680			175,369
Workers’ Compensation	74,725			75,947
Salary Retirement	107,637			109,956
Reclamation	33,394			33,788
Other	156,570			158,171
Total Deferred Credits and Other Liabilities	1,975,150			2,006,233
TOTAL LIABILITIES	6,483,669			6,430,072
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,680,338 Issued and Outstanding at March 31, 2015; 230,265,463 Issued and Outstanding at December 31, 2014	2,291			2,306
Capital in Excess of Par Value	2,412,587			2,424,102
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	3,053,412			3,054,150
Accumulated Other Comprehensive Loss	(170,563		)	(151,100		)
Total CONSOL Energy Inc. Stockholders’ Equity	5,297,727			5,329,458
TOTAL LIABILITIES AND EQUITY	$	11,781,396		$	11,759,530

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY



(Dollars in thousands, except per share data)	Common Stock			Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total CONSOL Energy Inc. Stockholders’ Equity
December 31, 2014	$	2,306		$	2,424,102		$	3,054,150		$	(151,100	)	$	5,329,458
(Unaudited)
Net Income	—			—			79,030			—			79,030
Other Comprehensive Loss	—			—			—			(19,463		)	(19,463		)
Comprehensive Income (Loss)	—			—			79,030			(19,463		)	59,567
Issuance of Common Stock	7			1,729			—			—			1,736
Retirement of Common Stock (2,213,100 shares)	(22		)	(17,683		)	(53,969		)	—			(71,674		)
Treasury Stock Activity	—			—			(11,399		)	—			(11,399		)
Tax Cost From Stock-Based Compensation	—			(3,042		)	—			—			(3,042		)
Amortization of Stock-Based Compensation Awards	—			7,481			—			—			7,481
Dividends ($0.0625 per share)	—			—			(14,400		)	—			(14,400		)
Balance at March 31, 2015	$	2,291		$	2,412,587		$	3,053,412		$	(170,563	)	$	5,297,727

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS



(Dollars in thousands)	Three Months Ended
(Unaudited)	March 31,
Operating Activities:	2015			2014
Net Income	$	79,030		$	116,003
Adjustments to Reconcile Net Income to Net Cash Provided By Continuing Operating Activities:
Net Loss from Discontinued Operations	—			5,687
Depreciation, Depletion and Amortization	150,594			129,116
Stock-Based Compensation	7,481			15,892
Gain on Sale of Assets	(2,165		)	(3,669		)
Loss on Debt Extinguishment	67,734			—
Unrealized Gain on Commodity Derivative Instruments	(60,004		)	—
Deferred Income Taxes	(21,200		)	8,149
Equity in Earnings of Affiliates	(11,323		)	(7,450		)
Changes in Operating Assets:
Accounts and Notes Receivable	26,523			(22,231		)
Inventories	(3,371		)	1,729
Prepaid Expenses	38,476			15,493
Changes in Other Assets	6,966			354
Changes in Operating Liabilities:
Accounts Payable	(17,720		)	16,595
Accrued Interest	42,719			51,233
Other Operating Liabilities	(68,711		)	18,260
Changes in Other Liabilities	(10,305		)	3,655
Other	3,646			1,125
Net Cash Provided by Continuing Operations	228,370			349,941
Net Cash Used in Discontinued Operating Activities	—			(13,839		)
Net Cash Provided by Operating Activities	228,370			336,102
Cash Flows from Investing Activities:
Capital Expenditures	(294,019		)	(451,009		)
Proceeds from Sales of Assets	2,108			125,528
Net Investments In Equity Affiliates	(27,992		)	(10,000		)
Net Cash Used in Investing Activities	(319,903		)	(335,481		)
Cash Flows from Financing Activities:
Proceeds from Short-Term Borrowings	760,500			—
Payments on Miscellaneous Borrowings	(2,478		)	(4,670		)
Payments on Long Term Notes, including Redemption Premium	(1,261,009		)	—
Proceeds from Securitization Facility	32,669			—
Proceeds from Issuance of Long-Term Notes	492,760			—
Tax Benefit from Stock-Based Compensation	15			92
Dividends Paid	(14,400		)	(14,351		)
Issuance of Common Stock	1,736			4,976
Treasury Stock Activity	—			(1		)
Purchases of Treasury Stock	(71,674		)	—
Debt Issuance and Financing Fees	(18,257		)	—
Net Cash Used in Financing Activities	(80,138		)	(13,954		)
Net Decrease in Cash and Cash Equivalents	(171,671		)	(13,333		)
Cash and Cash Equivalents at Beginning of Period	176,989			327,420
Cash and Cash Equivalents at End of Period	$	5,318		$	314,087

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 months ended March 31, 2015 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2014 has been derived from the Audited Consolidated Financial Statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2014 included in CONSOL Energy Inc.'s Form 10-K.

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

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



	Three Months Ended March 31,
	2015	2014
Anti-Dilutive Options	1,834,432	359,488
Anti-Dilutive Restricted Stock Units	85,018	—
Anti-Dilutive Performance Stock Options	802,804	—
	2,722,254	359,488

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



	Three Months Ended March 31,
	2015	2014
Options	76,028	265,339
Restricted Stock Units	449,005	334,399
Performance Share Units	497,134	378,971
	1,022,167	978,709

The weighted average exercise price per share of the options exercised during the three months ended March 31, 2015 and 2014 was $22.75 and $18.74, respectively.

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



	Three Months Ended March 31,
	2015		2014
Income from Continuing Operations	$	79,030	$	121,690
Loss from Discontinued Operations	—		(5,687		)
Net Income	$	79,030	$	116,003
Weighted Average Shares of Common Stock Outstanding:
Basic	229,734,412		229,526,033
Effect of Stock-Based Compensation Awards	712,287		1,341,493
Dilutive	230,446,699		230,867,526
Earnings per Share:
Basic (Continuing Operations)	$	0.34	$	0.53
Basic (Discontinued Operations)	—		(0.02		)
Total Basic	$	0.34	$	0.51

Dilutive (Continuing Operations)	$	0.34	$	0.53
Dilutive (Discontinued Operations)	—		(0.03		)
Total Dilutive	$	0.34	$	0.50

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



	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2014	$	121,521		$	(272,621	)	$	(151,100	)
Amounts Reclassified from Accumulated Other Comprehensive Income	(19,314		)	(149		)	(19,463		)
Balance at March 31, 2015	$	102,207		$	(272,770	)	$	(170,563	)

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



	Three Months Ended March 31,
	2015			2014
Derivative Instruments (Note 13)
Natural Gas Price Swaps and Options	$	(30,527	)	$	27,264
Tax Expense (Benefit)	11,213			(10,951		)
Net of Tax	$	(19,314	)	$	16,313
Actuarially Determined Long-Term Liability Adjustments (Note 4 and Note 5)
Amortization of Prior Service Costs	$	(14,812	)	$	(2,542	)
Recognized Net Actuarial Loss	14,573			10,646
Total	(239		)	8,104
Tax Expense (Benefit)	90			(2,985		)
Net of Tax	$	(149	)	$	5,119

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

On December 29, 2014, CNX Gas Company LLC (CNX Gas Company), a wholly-owned subsidiary of CONSOL Energy, finalized an agreement with Columbia Energy Ventures (CEVCO) to sublease approximately 20,000 acres of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. Up-front bonus consideration of up to $96,106 will be paid by CONSOL Energy over the next five years as drilling occurs in addition to royalties, of which $49,533 was recorded in Other Current Liabilities and $40,286 was recorded on a discounted basis in Other Long-term Liabilities. In the three months ended March 31, 2015, CONSOL Energy made payments to CEVCO totaling $15,216 which decreased the amount recorded in Other Current Liabilities to $34,317. As of March 31, 2015, the long-term portion of the liability remains unchanged at $40,286.

On December 12, 2014, CONSOL Energy completed the sale of its industrial supplies subsidiary, to an unrelated third party for net proceeds of approximately $51,000 of which $44,035 was received and included in cash flows from investing activities during the year ended December 31, 2014. In connection with the sale, CONSOL Energy signed a supply agreement under which, among other things, it will continue to purchase certain goods exclusively from the new entity for a period of at least three years. CONSOL Energy could also receive up to an additional $6,000 of cash consideration in the future, which has not been recognized in the consolidated financial statements as it is subject to future events. CONSOL Energy recorded a net loss on the sale of $30,845, which was included in Gain on Sale of Assets in the Consolidated Statement of Income.

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

In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unit of Dominion Resources Inc. The acreage, which is associated with Dominion’s Fink-Kennedy, Lost Creek, and Racket Newberne gas storage fields in West Virginia, lies in the northern portion of Lewis County and the southern portion of Harrison County. CONSOL Energy anticipates that over one-half of the acres will have wet gas. CONSOL Energy has acquired the gas rights to both the Marcellus Shale and the Upper Devonian formations in the storage fields. Consideration of up to $190,000 will be paid by CONSOL Energy in two installments: 50% was paid at closing and the remaining balance is due over time as the acres are drilled. In addition, CONSOL Energy will pay an overriding royalty to Dominion Resources based on a sliding scale. Finally, CONSOL Energy has committed to be an anchor shipper on Dominion’s transmission system, with the specific terms to be negotiated at a future date. CONSOL Energy paid $91,243 in 2013 related to this transaction. In the first quarter of 2014, CONSOL Energy made an additional bonus payment of $12,000 to Dominion Transmission. Noble Energy Inc., our joint venture partner, acquired 50% of the acres and reimbursed CONSOL Energy for 50% of the associated costs also in the first quarter of 2014.

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

NOTE 3—MISCELLANEOUS OTHER INCOME:



	Three Months Ended
	March 31,
	2015		2014
Equity in Earnings of Affiliates	$	11,323	$	7,450
Rental Income	9,598		14,908
Gathering Revenue	6,095		18,730
Coal Royalty Income	4,545		5,279
Right of Way Issuance	2,528		1,900
Interest Income	1,143		624
Other	2,834		6,163
Total Other Income	$	38,066	$	55,054

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

Components of net periodic benefit costs for the three months ended March 31, 2015 and 2014 are as follows:



	Pension Benefits						Other Post-Employment Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2015			2014			2015			2014
Service cost	$	2,350		$	4,308		$	—		$	2,331
Interest cost	8,580			9,151			6,995			12,097
Expected return on plan assets	(12,689		)	(12,747		)	—			—
Amortization of prior service credits	(176		)	(346		)	(14,636		)	(2,196		)
Recognized net actuarial loss	6,939			5,891			8,926			6,369
Net periodic benefit cost	$	5,004		$	6,257		$	1,285		$	18,601

For the three months ended March 31, 2015, $2,215 was paid to the pension trust from operating cash flows. Additional contributions to the pension trust are not expected to be significant for the remainder of 2015.

CONSOL Energy does not expect to contribute to the other post-employment benefit plan in 2015. The Company intends to pay benefit claims as they become due. For the three months ended March 31, 2015, $14,333 of other post-employment benefits have been paid.

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

Components of net periodic benefit costs for the three months ended March 31, 2015 and 2014 are as follows:



	CWP						Workers' Compensation
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2015			2014			2015			2014
Service cost	$	1,623		$	1,419		$	2,347		$	2,445
Interest cost	1,279			1,384			799			894
Amortization of actuarial gain	(1,394		)	(1,549		)	(8		)	(95		)
State administrative fees and insurance bond premiums	—			—			903			1,111
Net periodic benefit cost	$	1,508		$	1,254		$	4,041		$	4,355

CONSOL Energy does not expect to contribute to the CWP plan in 2015. The Company intends to pay benefit claims as they become due. For the three months ended March 31, 2015, $2,653 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2015. The Company intends to pay benefit claims as they become due. For the three months ended March 31, 2015, $5,306 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 6—INCOME TAXES:

The effective tax rate for the three months ended March 31, 2015 and 2014 was (47.9)% and 6.5%, respectively.

The effective rate for the three months ended March 31, 2015 differs from the U.S. federal statutory rate of 35% primarily due to a $59,285 income tax benefit for excess percentage depletion.

The effective rate for the three months ended March 31, 2014 differs from the U.S. federal statutory rate of 35% primarily due to a $27,422 income tax benefit for excess percentage depletion, an $8,820 discrete income tax benefit related to the completion of the Internal Revenue Service audit of tax years 2008 and 2009, and a $7,766 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.

There were no uncertain tax positions at March 31, 2015. The total amount of uncertain tax positions at March 31, 2014 were $2,540. If these uncertain tax positions were recognized, approximately $1,651, would have an affect on CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the three months ended March 31, 2015 and 2014.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. There was no accrued interest on uncertain tax positions as of March 31, 2015. As of March 31, 2014, the Company reported an accrued interest liability relating to uncertain tax positions of $1,351. The accrued interest liability included $4,849 of interest income that is reflected in the Company’s Consolidated Statements of Income for the three months ended March 31, 2014.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of March 31, 2015 and 2014, CONSOL Energy had no accrued liability for tax penalties.

CONSOL Energy and its subsidiaries file federal income tax returns with the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2010. The Company expects the Internal Revenue Service to begin its audit of tax years 2010 through 2013 in the second quarter of 2015.

NOTE 7—INVENTORIES:

Inventory components consist of the following:



	March 31, 2015		December 31, 2014
Coal	$	22,596	$	19,242
Supplies	82,648		82,631
Total Inventories	$	105,244	$	101,873

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

NOTE 8—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of its U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. On March 27, 2015, this facility was amended to allow the Company to receive, on a revolving basis, up to $100,000 of short-term funding and letters of credit. The receivables facility expires in July 2015. CONSOL Energy may also issue letters of credit against the facility, which decreases the amount available to be drawn upon.

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

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

At March 31, 2015 and December 31, 2014, eligible accounts receivable totaled $77,500 and $77,800, respectively. After taking into account outstanding letters of credit of $49,431 and $60,230, and outstanding borrowings there remained no subordinated retained interest at March 31, 2015 and $17,570 in subordinated retained interest at December 31, 2014. CONSOL Energy's management believes that the letters of credit will expire without being funded, and therefore, the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

Borrowings totaled $32,669 at March 31, 2015; there were no borrowings at December 31, 2014. These changes are reflected in the Net Cash Used in Financing Activities section of the Consolidated Statement of Cash Flows.

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 $196 and $279 for the three months ended March 31, 2015 and 2014, respectively. These costs have been recorded as financing fees which are included in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. No servicing asset or liability has been recorded at March 31, 2015.

NOTE 9—PROPERTY, PLANT AND EQUIPMENT:



	March 31, 2015		December 31, 2014
Coal and other plant and equipment	$	3,747,817	$	3,726,514
Intangible drilling cost	3,057,859		2,798,394
Proven gas properties	1,766,692		1,768,007
Unproven gas properties	1,554,505		1,540,835
Coal properties and surface lands	1,364,481		1,358,306
Gas gathering equipment	1,101,113		1,088,238
Gas wells and related equipment	754,918		716,748
Airshafts	467,455		468,924
Mine development	412,130		414,501
Coal advance mining royalties	389,175		386,245
Leased coal lands	253,615		263,946
Other gas assets	124,362		123,539
Gas advance royalties	20,204		20,580
Total Property Plant and Equipment	15,014,326		14,674,777
Less: Accumulated DD&A	4,647,745		4,512,305
Total Net PP&E	$	10,366,581	$	10,162,472

Industry Participation Agreements

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

CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 153,000 net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess is obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. As of March 31, 2015, Hess’ remaining carry obligation is $76,401. For the quarters ending March 31, 2015 and March 31, 2014, Hess' carry payments to CNX Gas Company reduced capital expenditures by $18,600 and $15,869, respectively.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 702,000 net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owns a 50% undivided interest. Under the agreement, as amended, Noble Energy is obligated to pay a total of approximately $1,846,000 in the form of a one-third drilling carry of certain of CONSOL Energy’s working interest obligations as the property is developed, subject to certain limitations. These limitations include the suspension of the carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. The carry was in effect from March 1, 2014, and remained in effect until November 1, 2014 when average natural gas prices fell below $4.00/MMbtu for three consecutive months. The carry continues to be suspended. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of March 31, 2015, Noble Energy’s remaining carry obligation is $1,626,135. For the quarter ending March 31, 2015 Noble's carry payments to CNX Gas Company reduced capital expenditures by $27,916. Payments received during the quarter ended March 31, 2015 were for expenditures made while the carry was in effect during 2014. For the quarter ending March 31, 2014 there was no carry related reductions to capital expenditures.

NOTE 10—SHORT-TERM NOTES PAYABLE:

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

The current facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders administrative agent and approved by the required number of lenders in good faith by calculating a value of CONSOL Energy's proved gas reserves.

The current facility contains a number of affirmative and negative covenants that limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The facility also requires that CONSOL Energy maintains a minimum interest coverage ratio of 2.50 to 1.00 which is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries, measured quarterly. CONSOL Energy must also maintain a minimum current ratio of 1.00 to 1.00 which is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver and accounts receivable securitization facility, measured quarterly. At March 31, 2015, the interest coverage ratio was 4.72 to 1.00 and the current ratio was 1.60 to 1.00. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and permits CONSOL Energy to separate its gas and coal businesses if the leverage ratio (which is, essentially, the ratio of debt to EBITDA) of the E&P business immediately after the separation would not be greater than 2.75 to 1.00.

At March 31, 2015, the $2,000,000 facility had $760,500 of borrowings outstanding and $214,650 of letters of credit outstanding, leaving $1,024,850 of unused capacity. At December 31, 2014, the $2,000,000 facility had no borrowings outstanding and $244,418 of letters of credit outstanding, leaving $1,755,582 of unused capacity.

On March 9, 2015, Consol Pennsylvania Coal Company LLC (CPCC) and Conrhein Coal Company (Conrhein) which are wholly owned subsidiaries of the Company, entered into a $600,000 commitment for a senior secured term loan facility. If drawn, the maturity date of the term loan facility is March 9, 2018. The facility is secured by the thermal coal assets related to CONSOL Energy’s existing Pennsylvania operations along with CONSOL Energy providing a guarantee to the lenders and a pledge of its equity interests in CPCC and Conrhein. At March 31, 2015, the term loan facility is undrawn.

The term loan commitment will expire on the earlier of (1) December 31, 2015 or (2) the consummation of the CNX Coal Resources LP initial public offering. The term loan facility will contain affirmative and negative covenants that, among other things, limit the ability to dispose of assets, pay dividends, merge with another corporation and incur indebtedness. The term loans shall bear interest at a rate per annum equal to LIBOR plus 3.0% or Base Rate plus 2.0%.

NOTE 11—LONG-TERM DEBT:



	March 31, 2015		December 31, 2014
Debt:

Senior notes due April 2020 at 8.25%, issued at par value	$	76,978	$	1,014,800
Senior notes due March 2021 at 6.375%, issued at par value	20,824		250,000
Senior notes due April 2022 at 5.875%, including amortization of bond premium	1,856,283		1,856,506
Senior notes due April 2023 at 8.00%, including amortization of bond discount	492,760		—
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.91% weighted average interest rate for March 31, 2015 and December 31, 2014)	13,473		13,473
Other long-term note maturing in 2018 (total value of $4,129 and $4,473 less unamortized discount of $555 and $643 at March 31, 2015 and December 31, 2014, respectively).	3,574		3,830
	2,566,757		3,241,474
Less amounts due in one year *	5,076		5,052
Long-Term Debt	$	2,561,681	$	3,236,422

* Excludes current portion of Capital Lease Obligations of $8,166 and $7,964 at March 31, 2015 and December 31, 2014, respectively.

Accrued interest related to Long-Term Debt of $54,118 and $51,159 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at March 31, 2015 and December 31, 2014, respectively.

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

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. CONSOL Energy accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's 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 $389,011.

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

Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of forced-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations CNX Gas Company failed to either pay royalties due to conflicting claimants, or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed their Renewed Motion for Class Certification, seeking to certify a class for purposes of an accounting of escrowed and suspended royalties. The Company’s opposition to the Renewed Motion is due on June 23, 2015, and the Court has set aside September 8 through 10, 2015 for a hearing. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia. The putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Court of Appeals for the Fourth Circuit. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed their Renewed Motion for Class Certification, seeking to certify a class for purposes of an accounting of escrowed and suspended royalties. The Company’s opposition to the Renewed Motion is due on June 23, 2015, and the Court has set aside September 8 through 10, 2015 for a hearing. CONSOL Energy continues to believe this action cannot properly proceed as a class action in any form, believes the case has meritorious defenses, and intends to defend it vigorously. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

Clean Water Act - Bailey Mine: The Company received from the U.S. EPA on April 8, 2011 a request for information relating to National Pollutant Discharge Element System Permit compliance at the Company's Bailey and Enlow Fork Mines. In response, CONSOL Pennsylvania Coal Company submitted water discharge monitoring and other data to the EPA. In early 2013, the case was referred to the U.S. Department of Justice (DOJ), and the Pennsylvania Department of Environmental Protection also became involved. On December 18, 2014, the DOJ provided the Company a proposed Consent Decree to resolve certain Clean Water Act and Clean Streams Law claims against CONSOL Energy Inc. and CONSOL Pennsylvania Coal Company with respect to the Bailey Mine Complex. The parties continue to negotiate the terms of the proposed Consent Decree. The Company has established an accrual to cover its estimated liability in this matter. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, an accrual may not have been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, but are not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having been completed, unavailability of expert reports on damages and non-monetary issues are being tried. For example, in instances where a gas lease termination is sought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilled on the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period. An estimate is calculated, if applicable, when sufficient information becomes available.

Virginia Mine Void Litigation: The Company is currently defending five lawsuits naming Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, and/or CONSOL Energy. Four of the lawsuits are pending in the U.S. District Court for the Western District of Virginia. The Complaints seek damages and injunctive relief in connection with the transfer of water from mining activities at the Company's Buchanan Mine into void spaces in inactive ICCC mines adjacent to the Buchanan operations, which are voids ostensibly underlying plaintiffs' properties. While some of the plaintiffs have an ownership interest in the coal, others have some interest in one or more of the fee, surface, coal, oil/gas or other mineral estates. The suits allege that the water storage precludes access to and has damaged coal, impeded coalbed methane gas production and was made without compensation to the property owners. Plaintiffs seek recovery in tort, contract and trespass assumpsit (quasi-contract). The suits each seek damages between $50,000 and in excess of $100,000 plus punitive damages. The Company intends to vigorously defend these suits. The Company has established an accrual to cover the low end of the estimated range of possible losses. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

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 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 April 22, 2015, the Superior Court ruled in favor of the Company on all issues and affirmed each of the trial court orders and judgments that was appealed.

Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources Inc., and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern West Virginia. EQT was the original lessee, but farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty. Dominion Resources sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion Resources' sale of the subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and/or (ii) the subsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. The parties have reached a settlement in principle of this matter, which will be dismissed with prejudice.

At March 31, 2015, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the

maximum potential total of future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities in the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	94,947	$	75,624	$	19,323	$	—	$	—
Environmental	4,786		4,186		600		—		—
Other	164,347		164,347		—		—		—
Total Letters of Credit	264,080		244,157		19,923		—		—
Surety Bonds:
Employee-Related	181,720		181,720		—		—		—
Environmental	553,656		545,391		8,265		—		—
Other	24,454		24,449		4		1
Total Surety Bonds	759,830		751,560		8,269		1		—
Guarantees:
Coal	108,550		83,500		25,050		—		—
Other	84,421		42,119		16,939		12,649		12,714
Total Guarantees	192,971		125,619		41,989		12,649		12,714
Total Commitments	$	1,216,881	$	1,121,336	$	70,181	$	12,650	$	12,714

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

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

CONSOL Energy and CNX Gas Company enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of March 31, 2015, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	263,985
1 - 3 years	314,084
3 - 5 years	197,923
More than 5 years	626,620
Total Purchase Obligations	$	1,402,612

NOTE 13—DERIVATIVE INSTRUMENTS:

CONSOL Energy enters into economic derivative instruments to manage its exposure to commodity price volatility. CONSOL Energy de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future gas commodity hedges on a mark-to-market basis with changes in fair value recorded in current period earnings. In connection with this change, CONSOL Energy froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014 and will reclassify balances to earnings as the underlying physical transactions occur, unless it is no longer probable that the physical transaction will occur at which time the related Other Comprehensive Income (OCI) will be immediately recorded in earnings. In November 2014, CONSOL Energy entered into basis only swaps that did not qualify for hedge accounting. These swaps were entered into to decrease the risk related to pricing differentials between local markets and NYMEX.

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

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

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

CONSOL Energy’s commodity derivative instruments accounted for a total notional amount of production of 213.3 bcf at March 31, 2015 and are forecasted to settle through 2017. At December 31, 2014, the commodity derivative instruments accounted for a total notional amount of production of 215.9 bcf. At March 31, 2015, the basis only swaps were for notional amounts of 8.0 bcf and are forecasted to settle through 2015. At December 31, 2014, the basis only swaps were for notional amounts of 10.6 bcf.

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



Asset Derivative Instruments					Liability Derivative Instruments
	March 31, 2015		December 31, 2014			March 31, 2015		December 31, 2014
Commodity Derivative Instruments
Prepaid Expense	$	138,772	$	123,676	Other Liabilities	$	272	$	—
Other Assets	85,463		68,656		Other Accrued Liabilities	526		—
Total Asset	$	224,235	$	192,332	Total Liability	$	798	$	—

Basis Only Swaps
Prepaid Expense	$	72	$	1,064	Other Accrued Liabilities	$	962	$	327

The commodity derivative instruments resulted in a gain of $61,631 being recorded in Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income during the quarter ending March 31, 2015.

The basis only swaps resulted in a loss of $1,627 being recorded in Unrealized Gain on Commodity Derivative Instruments on the Consolidated Statements of Income during the quarter ending March 31, 2015.

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



	Three Months Ended March 31,
	2015		2014
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	121,521	$	42,493
Loss recognized in Accumulated OCI	—		(46,965		)
Less: Gain (Loss) reclassified from Accumulated OCI (Net of tax: $11,213, ($10,951))	19,314		(16,313		)
Ending Balance – Accumulated OCI	$	102,207	$	11,841
Gain recognized in Outside Sales for ineffectiveness *	$	—	$	355

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

CONSOL Energy expects to reclassify an additional $58,737, net of tax of $33,841, out of Accumulated Other Comprehensive Income over the remaining period ended December 31, 2015.

NOTE 14—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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

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

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

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

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

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

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



	Fair Value Measurements at March 31, 2015						Fair Value Measurements at December 31, 2014
Description	(Level 1)		(Level 2)		(Level 3)		(Level 1)		(Level 2)		(Level 3)
Gas Derivatives	$	—	$	222,547	$	—	$	—	$	193,069	$	—
Murray Energy Guarantees	$	—	$	—	$	1,275	$	—	$	—	$	1,275

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

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

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

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

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

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



	March 31, 2015						December 31, 2014
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	5,318		$	5,318		$	176,989		$	176,989
Short-Term Notes Payable	$	(760,500	)	$	(760,500	)	$	—		$	—
Borrowings Under Securitization Facility	$	(32,669	)	$	(32,669	)	$	—		$	—
Long-Term Debt	$	(2,566,757	)	$	(2,398,682	)	$	(3,241,474	)	$	(3,169,154	)

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

NOTE 15—SEGMENT INFORMATION:

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

The principal activities of the Coal division, which includes three reportable segments, are mining, preparation and marketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division's reportable segments are Pennsylvania (PA) Operations, Virginia (VA) Operations, and Other Coal. Each of these reportable segments includes a number of operating segments (individual mines). For the three months ended March 31, 2015, the PA Operations aggregated segment includes the following mines: Bailey Mine, Enlow Fork Mine, and Harvey Mine and the corresponding preparation plant facilities. For the three months ended March 31, 2015, the VA Operations aggregated segment includes the Buchanan Mine and the corresponding preparation plant facilities. For the three months ended March 31, 2015, the Other Coal segment includes the Miller Creek Complex, coal terminal operations, the Company's purchased coal activities, idled mine activities and general and administrative activities, as well as various other activities assigned to the Coal division but not allocated to each individual mine.

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

In the preparation of the following information, intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level for E&P and are not allocated between each individual E&P segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy, whereby each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

Industry segment results for the three months ended March 31, 2015 are:



	Marcellus Shale		Utica Shale			Coalbed Methane		Other Gas		Total E&P		PA Operations		VA Operations		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	137,360	$	18,603		$	74,984	$	23,633	$	254,580	$	384,437	$	80,515	$	31,714		$	496,666	$	—	$	—		$	751,246	(A)
Other outside sales	—		—			—		—		—		—		—		13,130			13,130		—		—			13,130
Sales—purchased gas	—		—			—		3,597		3,597		—		—		—			—		—		—			3,597
Sales—gas royalty interests	—		—			—		14,859		14,859		—		—		—			—		—		—			14,859
Freight—outside	—		—			—		—		—		2,369		—		4,156			6,525		—		—			6,525
Intersegment transfers	—		—			547		—		547		—		—		—			—		—		(547		)	—
Total Sales and Freight	$	137,360	$	18,603		$	75,531	$	42,089	$	273,583	$	386,806	$	80,515	$	49,000		$	516,321	$	—	$	(547	)	$	789,357
Earnings (Loss) Before Income Taxes	$	42,244	$	(5,053	)	$	14,732	$	24,068	$	75,991	$	98,402	$	22,567	$	(15,087	)	$	105,882	$	102	$	(128,548	)	$	53,427	(B)
Segment assets										$	7,530,979	$	2,100,349	$	344,098	$	1,583,303		$	4,027,750	$	78,553	$	144,114		$	11,781,396	(C)
Depreciation, depletion and amortization										$	85,104	$	44,850	$	11,975	$	8,658		$	65,483	$	7	$	—		$	150,594
Capital expenditures										$	250,303	$	32,936	$	6,234	$	1,671		$	40,841	$	2,875	$	—		$	294,019

(A) Included in the Coal segment are sales of $120,577 to Xcoal Energy & Resources and sales of $84,623 to Duke Energy, each comprising over 10% of sales.

(B) Includes equity in earnings of unconsolidated affiliates of $8,377, $2,938 and $8 for E&P, Coal and All Other, respectively.

Industry segment results for the three months ended March 31, 2014 are:



	Marcellus Shale		Utica		Coalbed Methane		Other Gas			Total E&P		PA Operations		VA Operations			Other Coal			Total Coal		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	124,957	$	7,031	$	96,071	$	38,239		$	266,298	$	412,081	$	84,505		$	38,095		$	534,681	$	—		$	—		$	800,979	(D)
Other outside sales	—		—		—		—			—		—		—			10,483			10,483		58,804			—			69,287
Sales—purchased gas	—		—		—		3,574			3,574		—		—			—			—		—			—			3,574
Sales—gas royalty interests	—		—		—		26,645			26,645		—		—			—			—		—			—			26,645
Freight—outside	—		—		—		—			—		7,430		358			2,157			9,945		—			—			9,945
Intersegment transfers	—		—		897		—			897		—		—			—			—		19,311			(20,208		)	—
Total Sales and Freight	$	124,957	$	7,031	$	96,968	$	68,458		$	297,414	$	419,511	$	84,863		$	50,735		$	555,109	$	78,115		$	(20,208	)	$	910,430
Earnings (Loss) Before Income Taxes	$	59,105	$	539	$	33,619	$	(13,519	)	$	79,744	$	132,790	$	(881	)	$	(21,510	)	$	110,399	$	(1,737	)	$	(58,227	)	$	130,179	(E)
Segment assets										$	6,521,994	$	2,027,866	$	372,745		$	1,865,849		$	4,266,460	$	193,679		$	602,342		$	11,584,475	(F)
Depreciation, depletion and amortization										$	71,729	$	35,162	$	11,712		$	9,992		$	56,866	$	521		$	—		$	129,116
Capital expenditures										$	265,970	$	174,194	$	6,242		$	3,647		$	184,083	$	976		$	—		$	451,029


(D)	Included in the Coal segment are sales of $118,884 to Xcoal Energy & Resources, which comprises over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $5,814, $2,860 and $(1,224) for E&P, Coal and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $223,874, $84,864 and $387 for E&P, Coal and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended March 31,
	2015			2014
Segment Earnings Before Income Taxes for total reportable business segments	$	181,873		$	190,143
Segment Earnings Before Income Taxes for all other businesses	102			(1,737		)
Interest (expense), net (G)	(55,122		)	(50,931		)
Evaluation fees for non-core asset dispositions (G)	(788		)	—
Other corporate items (G)	(4,904		)	(7,296		)
Loss on debt extinguishment	(67,734		)	—
Earnings Before Income Taxes	$	53,427		$	130,179



Total Assets:	March 31,
Total Assets:	2015		2014
Segment assets for total reportable business segments	$	11,558,729	$	10,788,454
Segment assets for all other businesses	78,553		193,679
Items excluded from segment assets:
Cash and other investments (G)	5,252		300,090
Recoverable income taxes	20,567		4,434
Deferred tax assets	74,725		265,226
Bond issuance costs	43,570		32,592
Total Consolidated Assets	$	11,781,396	$	11,584,475

_________________________

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

NOTE 16—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $76,978, 8.250% per annum senior notes due April 1, 2020, the $20,824, 6.375% per annum senior notes due March 1, 2021, the $1,856,283, 5.875% per annum senior notes due April 15, 2022, and the $492,760, 8.000% per annum senior notes due April 1, 2023 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally, guaranteed by substantially all subsidiaries of CONSOL Energy. In December 2014, the Company completed the sale of its industrial supplies subsidiary, which constituted the only significant non-guarantor subsidiary. Subsequent to this sale, the Parent Issuer does not have independent assets or operations and the remaining non-guarantor subsidiaries are minor. As a result, condensed consolidating financial statements are not required for the periods subsequent to December 31, 2014. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries for the periods prior to January 1, 2015. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the Three Months Ended March 31, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	267,194	$	—	$	—		$	(896	)	$	266,298
Coal Sales	—			—		534,681		—			—			534,681
Other Outside Sales	—			—		10,483		58,804			—			69,287
Gas Royalty Interests and Purchased Gas Sales	—			30,219		—		—			—			30,219
Freight-Outside Coal	—			—		9,945		—			—			9,945
Miscellaneous Other Income	169,567			28,157		24,813		2,302			(169,785		)	55,054
Gain (Loss) on Sale of Assets	—			3,152		514		3			—			3,669
Total Revenue and Other Income	169,567			328,722		580,436		61,109			(170,681		)	969,153
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			29,243		—		—			—			29,243
Transportation, Gathering and Compression	—			53,782		—		—			—			53,782
Production, Ad Valorem, and Other Fees	—			10,187		—		—			—			10,187
Direct Administrative and Selling	—			11,653		—		—			—			11,653
Depreciation, Depletion and Amortization	—			71,729		—		—			—			71,729
Exploration and Production Related Other Costs	—			3,099		—		—			—			3,099
Production Royalty Interests and Purchased Gas Costs	—			26,108		—		—			(12		)	26,096
Other Corporate Expenses	—			26,164		—		—			—			26,164
General and Administrative	—			17,364		—		—			—			17,364
Total Exploration and Production Costs	—			249,329		—		—			(12		)	249,317
Coal Costs
Operating and Other Costs	11,031			—		323,675		—			(896		)	333,810
Royalties and Production Taxes	—			—		26,488		—			—			26,488
Direct Administrative and Selling	—			—		11,542		—			—			11,542
Depreciation, Depletion and Amortization	156			—		56,710		—			—			56,866
Freight Expense	—			—		9,945		—			—			9,945
General and Administrative Costs	—			—		12,709		—			—			12,709
Other Corporate Expenses	19,295			—		—		—			—			19,295
Total Coal Costs	30,482			—		441,069		—			(896		)	470,655
Other Costs
Miscellaneous Operating Expense	7,237			—		288		58,671			1,144			67,340
General and Administrative Costs	—			—		210		—			—			210
Depreciation, Depletion and Amortization	6			—		42		473			—			521
Interest Expense	48,433			1,809		1,584		63			(958		)	50,931
Total Other Costs	55,676			1,809		2,124		59,207			186			119,002
Total Costs And Expenses	86,158			251,138		443,193		59,207			(722		)	838,974
Earnings Before Income Tax	83,409			77,584		137,243		1,902			(169,959		)	130,179
Income Taxes	(32,594		)	30,714		9,649		720			—			8,489
Income From Continuing Operations	116,003			46,870		127,594		1,182			(169,959		)	121,690
Income From Discontinued Operations, net	—			—		—		(5,687		)	—			(5,687		)
Net Income (Loss)	$	116,003		$	46,870	$	127,594	$	(4,505	)	$	(169,959	)	$	116,003

Balance Sheet at December 31, 2014:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	145,239		$	30,682		$	—		$	1,068		$	—		$	176,989
Accounts and Notes Receivable:
Trade	—			117,912			—			141,905			—			259,817
Other Receivables	25,497			309,247			12,390			12			—			347,146
Inventories	—			14,748			87,125			—			—			101,873
Recoverable Income Taxes	79,426			(59,025		)	—			—			—			20,401
Deferred Income Taxes	99,776			(33,207		)	—			—			—			66,569
Prepaid Expenses	38,418			129,796			25,341			—			—			193,555
Total Current Assets	388,356			510,153			124,856			142,985			—			1,166,350
Property, Plant and Equipment:
Property, Plant and Equipment	158,555			8,066,308			6,449,914			—			—			14,674,777
Less-Accumulated Depreciation, Depletion and Amortization	108,432			1,497,569			2,906,304			—			—			4,512,305
Total Property, Plant and Equipment-Net	50,123			6,568,739			3,543,610			—			—			10,162,472
Other Assets:
Investment in Affiliates	12,571,886			121,721			27,544			—			(12,568,193		)	152,958
Other	172,884			71,339			33,527			—			—			277,750
Total Other Assets	12,744,770			193,060			61,071			—			(12,568,193		)	430,708
Total Assets	$	13,183,249		$	7,271,952		$	3,729,537		$	142,985		$	(12,568,193	)	$	11,759,530
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	86,313		$	385,381		$	60,279		$	—		$	—		$	531,973
Accounts Payable (Recoverable)-Related Parties	4,499,174			182,758			(5,333,209		)	(68,873		)	720,150			—
Current Portion of Long-Term Debt	2,485			6,602			3,929			—			—			13,016
Short-Term Notes Payable	—			720,150			—			—			(720,150		)	—
Other Accrued Liabilities	119,484			172,787			310,701			—			—			602,972
Total Current Liabilities	4,707,456			1,467,678			(4,958,300		)	(68,873		)	—			1,147,961
Long-Term Debt:	3,124,129			37,342			114,407			—			—			3,275,878
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(148,925		)	474,517			—			—			—			325,592
Postretirement Benefits Other Than Pensions	—			—			703,680			—			—			703,680
Pneumoconiosis Benefits	—			—			116,941			—			—			116,941
Mine Closing	—			—			306,789			—			—			306,789
Gas Well Closing	—			116,930			58,439			—			—			175,369
Workers’ Compensation	—			—			75,947			—			—			75,947
Salary Retirement	109,956			—			—			—			—			109,956
Reclamation	—			—			33,788			—			—			33,788
Other	61,175			94,378			2,618			—			—			158,171
Total Deferred Credits and Other Liabilities	22,206			685,825			1,298,202			—			—			2,006,233
Total CONSOL Energy Inc. Stockholders’ Equity	5,329,458			5,081,107			7,275,228			211,858			(12,568,193		)	5,329,458
Total Liabilities and Equity	$	13,183,249		$	7,271,952		$	3,729,537		$	142,985		$	(12,568,193	)	$	11,759,530

Cash Flow for the Three Months Ended March 31, 2014 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	(11,711	)	$	219,148		$	108,944		$	14,160		$	19,400		$	349,941
Net Cash Used In Discontinued Operating Activities	—			—			—			(13,839		)	—			(13,839		)
Net Cash Provided by (Used in) Operating Activities	$	(11,711	)	$	219,148		$	108,944		$	321		$	19,400		$	336,102
Cash Flows from Investing Activities:
Capital Expenditures	$	(531	)	$	(265,970	)	$	(184,508	)	$	—		$	—		$	(451,009	)
Proceeds From Sales of Assets	—			49,470			76,055			3			—			125,528
(Investments in), net of Distributions from, Equity Affiliates	—			(12,000		)	2,000			—			—			(10,000		)
Net Cash (Used in) Provided by Continuing Operations	$	(531	)	$	(228,500	)	$	(106,453	)	$	3		$	—		$	(335,481	)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	$	(495	)	$	—		$	(3,947	)	$	(228	)	$	—		$	(4,670	)
Payments on Short-Term Borrowings	—			19,400			—			—			(19,400		)	—
Tax Benefit from Stock-Based Compensation	92			—			—			—			—			92
Dividends (Paid)	(14,351		)	—			—			—			—			(14,351		)
Proceeds from Issuance of Common Stock	4,976			—			—			—			—			4,976
Treasury Stock Activity	(1		)	—			—			—			—			(1		)
Other Financing Activities	—			(1,456		)	1,456			—			—			—
Net Cash (Used in) Provided by Continuing Operations	$	(9,779	)	$	17,944		$	(2,491	)	$	(228	)	$	(19,400	)	$	(13,954	)

Statement of Comprehensive Income for the Three Months Ended March 31, 2014 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors			Elimination			Consolidated
Net Income (Loss)	$	116,003		$	46,870		$	127,594	$	(4,505	)	$	(169,959	)	$	116,003
Other Comprehensive (Loss) Income:
Actuarially Determined Long-Term Liability Adjustments	5,119			—			5,119		—			(5,119		)	5,119
Net (Decrease) Increase in the Value of Cash Flow Hedge	(46,965		)	(46,965		)	—		—			46,965			(46,965		)
Reclassification of Cash Flow Hedge from OCI to Earnings	16,313			16,313			—		—			(16,313		)	16,313
Other Comprehensive (Loss) Income:	(25,533		)	(30,652		)	5,119		—			25,533			(25,533		)
Comprehensive Income (Loss)	$	90,470		$	16,218		$	132,713	$	(4,505	)	$	(144,426	)	$	90,470

NOTE 17—RELATED PARTY TRANSACTIONS:

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

On May 30, 2014, CONE Gathering LLC formed CONE Midstream Partners, LP (the Partnership). On September 30, 2014, CONE Gathering LLC contributed certain assets and liabilities to the Partnership, which closed on an initial public offering of 20,125,000 of its common units at a per unit price of $22.00, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters (the CONE IPO). The Partnership received net proceeds of $413,005 in connection with the CONE IPO, which is net of underwriting discounts, commissions, structuring fees, and other offering expenses of $29,745. The Partnership distributed $203,986 of the net proceeds from the CONE IPO to CNX Gas Company, which CONSOL Energy recorded as a return on equity investments within cash flows from operating activities and as a net investment in equity affiliates within cash flows from investing activities, pursuant to the cumulative earnings approach. Under this approach, all distributions received by the investor are deemed to be returns on the investment unless the cumulative distributions exceed the cumulative equity in earnings recognized by the investor. The excess distributions are deemed to be returns of the investment and are classified as investing cash flows.

During the three months ended March 31, 2015 there was $3,608 of additional capital contributions to CONE Gathering, LLC and $30,487 to CONE Midstream Partners, LP. The capital contributions were offset, in part, by $4,103 of distributions from CONE Midstream Partners, LP. During the three months ended March 31, 2014 there was $12,000 of additional capital contributions to CONE Gathering, LLC.

Following the CONE IPO, CONE Gathering LLC has a 2% general partner interest in the Partnership, while each sponsor has a 32.1% limited partner interest. CNX Gas Company accounts for its portion of the earnings in the Partnership under the equity method of accounting. At March 31, 2015, CNX Gas Company and Noble Energy each continue to own a 50% interest in the assets of CONE Gathering LLC that were not contributed to the Partnership. Equity in earnings of affiliates during the three months ended March 31, 2015 and 2014 related to CONE Gathering LLC was $3,138 and $4,401, respectively. Equity in earnings of affiliates related to CONE Midstream Partners, LP. was $4,518 during the three months ended March 31, 2015.

During the three months ended March 31, 2015 and 2014, CONE Gathering LLC (prior to September 30, 2014) and the Partnership (after September 30, 2014) provided gathering services to CNX Gas Company in the ordinary course of business totaling $22,360 and $11,825 respectively. These costs were included in Exploration and Production Costs - Transportation, Gathering and Compression on CONSOL Energy’s accompanying Consolidated Statements of Income. At March 31, 2015 and March 31, 2014, CONSOL Energy had a net payable of $8,137 and $5,352 respectively, due to both the Partnership and CONE Gathering LLC primarily for accrued but unpaid gathering services. The net payable for both periods is included in Accounts Payable on CONSOL Energy’s accompanying Consolidated Balance Sheets.

NOTE 18—STOCK REPURCHASE:

In December 2014, CONSOL Energy's Board of Directors approved a stock repurchase program under which CONSOL Energy may purchase from time to time up to $250,000 of its common stock over the next two years. Under the terms of the program, CONSOL Energy may make repurchases in the open market, in privately negotiated transactions, accelerated repurchase programs or in structured share repurchase programs. Any repurchases of common stock will be funded from available cash on hand or short-term borrowings. The program does not obligate CONSOL Energy to acquire any particular amount of common stock, and it may be modified or suspended at any time at the Company's discretion. The program will be conducted in compliance with applicable legal requirements and within the limits imposed by any credit agreement, receivables purchase agreement or indenture and shall be subject to market conditions and other factors. During the three months ended March 31, 2015, 2,213,100 shares were repurchased and retired at an average price of $32.37 per share.

NOTE 19—RECENT ACCOUNTING PRONOUNCEMENTS:

In February 2015, the Financial Accounting Standards Board (FASB) issued Update 2015-02 - Consolidation (Topic 810): Amendments to the Consolidation Analysis. The objective of the amendments in this update is to change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The amendments in this update affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments: (1) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities; (2) eliminate the presumption that a general partner should consolidate a limited partnership; (3) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships; and (4) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. The amendments in this update affect the following areas: (1) limited partnerships and similar legal entities; (2) evaluating fees paid to a decision maker or a service provider as a variable interest; (3) the effect of fee arrangements on the primary beneficiary determination; (4) the effect of related parties on the primary beneficiary determination; and (5) certain investment funds. Current GAAP includes different requirements for performing a consolidation analysis if, among other factors, the entity under evaluation is any one of the following: (1) a legal entity that qualifies for the indefinite deferral of Statement 167; (2) a legal entity that is within the scope of Statement 167; and (3) a limited partnership or similar legal entity that is considered a voting interest entity. Under the amendments in this update, all reporting entities are within the scope of Subtopic 810-10, Consolidation-Overall, including limited partnerships and similar legal entities, unless a scope exception applies. The presumption that a general partner controls a limited partnership has been eliminated. Overall, the amendments in this update are an improvement to current GAAP because they simplify the Codification and reduce the number of consolidated models through the elimination of the indefinite deferral of Statement 167 and because they place more emphasis on risk of loss when determining a controlling financial interest. The amendments in this update are effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the impact this guidance may have on CONSOL Energy's financial statements.

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

In April 2015, the FASB issued update 2015-04 - Compensation-Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer's Defined Benefit Obligation and Plan Assets. This update is part of the FASB's initiative

to reduce complexity in accounting standards (the Simplification Initiative). If a contribution or significant event (such as a plan amendment, settlement, or curtailment that calls for a remeasurement in accordance with existing requirements) occurs between the month-end date used to measure defined benefit plan assets and obligations and an entity's fiscal year-end, the entity should adjust the measurement of defined benefit plan assets and obligations to reflect the effects of those contributions or significant events. However, an entity should not adjust the measurement of defined benefit plan assets and obligations for other events that occur between the month-end measurement and the entity's fiscal year-end that are not caused by the entity (for example, changes in market prices or interest rates). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations (for example, a partial settlement), the amendments in this update also provide a practical expedient that permits the entity to remeasure defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this update. The amendments in this update are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Earlier application is permitted. The Company believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

In April 2015, the FASB issued update 2015-05 - Intangibles-Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. This update is part of the FASB's initiative to reduce complexity in accounting standards (the Simplification Initiative). Existing GAAP does not include explicit guidance about a customer's accounting for fees paid in a cloud computing arrangement. Examples of cloud computing arrangements include software as a service, platform as a service, infrastructure as a service, and other similar hosting arrangements. Guidance was added to Subtopic 350-40, Intangibles-Goodwill and Other-Internal-Use Software, which will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. For public business entities, the amendments will be effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted. The Company believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

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. Management believes adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.


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

General

For the first quarter of 2015, CONSOL Energy's average sales price for natural gas, natural gas liquids, oil, and condensate was $3.56 per Mcfe. CONSOL Energy's average price for natural gas was $3.10 per Mcf for the quarter and, including hedging, was $3.58 per Mcf. During the quarter, CONSOL Energy produced NGL, oil, and condensate volumes of 8.1 Bcfe, or 11% of the company's total gas equivalent volumes. These liquids volumes were over four times greater than the year-earlier quarter, which then comprised 4% of the company's total gas equivalent volumes. The average realized price for all liquids for the first quarter of 2015 was $20.95 per barrel.

CONSOL Energy recently entered into an innovative sales agreement with a major utility customer that allows for contractual volumes to be either coal or natural gas depending on which one of CONSOL Energy’s products is more cost-effective for the utility for a given month. This agreement is an example of how CONSOL Energy is using the strength of its coal and natural gas assets to provide unique value to its customers.

The company currently has a total of 1.1 Bcf per day of available firm transportation capacity. This is composed of 0.8 Bcf per day of firm capacity on existing pipelines and an additional 0.3 Bcf per day of long-term firm sales with major customers that have their own firm capacity. Additionally, CONSOL Energy has contracted volumes of approximately 0.6 Bcf per day on several pipeline projects that will be completed over the next several years. Even with the future expiration of certain transportation contracts, this will increase the company’s effective firm transportation capacity to approximately 1.7 Bcf per day. The average demand cost for the existing firm capacity is approximately $0.28 per MMBtu. The average demand cost for the existing and committed firm capacity is approximately $0.33 per MMBtu.

In addition to firm transportation capacity, CONSOL Energy has developed a processing portfolio to support the projected volumes from its wet production areas. The company has agreements in place to support the processing of approximately 0.3 Bcf per day of gross natural gas volumes growing to approximately 0.4 Bcf per day in the next twelve months.

CONSOL Energy’s Pennsylvania Coal Operations had a strong first quarter for production, shipments, and tons sold. While demand and pricing in spot markets remain challenged, CONSOL Energy’s low cost operations allow the company to not only participate in these short-term markets at positive margins, but to also expand its customer base. Internationally, new customers continue to test CONSOL Energy coal, and domestically, the company is steadily building a portfolio with targeted power plants that CONSOL Energy expects, will not only endure in future energy markets, but also have the potential to increase their consumption of coal.

During the quarter, CONSOL Energy sold 6.5 million tons of coal to 39 different end users. CONSOL Energy’s customers continue to demonstrate a steady demand for coal through term contracts that vary in length. During the quarter, CONSOL Energy contracted for 1.9 million additional tons for 2015, bringing the total firm and priced contracted position to 22.6 million tons, or 88% of estimated sales volumes based on the midpoint of guidance. For 2016, CONSOL Energy contracted for 1.1 million additional tons, bringing the total firm and priced contracted position to 12.9 million tons, or 50% (and sold position to 14.4 million tons, or 56%) of expected sales volumes based on the midpoint of guidance. For 2017 and 2018 combined, CONSOL Energy’s committed position is averaged at approximately 40% of expected sales volumes.

The Buchanan Mine continues to demonstrate industry leading cost performance that allows the operations to maintain positive margins in today’s metallurgical coal markets and expand its portfolio of customers. This positions the mine to be the best suited domestic metallurgical coal production facility to take advantage of markets when they rebound.

In the first quarter, CONSOL Energy sold 1.2 million tons of its Buchanan low-vol coal, which included a new sales opportunity to a significant metallurgical coal end user in China. The new opportunity in China, combined with existing business from traditional customers, has enabled CONSOL Energy to exceed its production forecast at the Buchanan Mine in the first quarter. During the quarter, CONSOL Energy contracted for 0.7 million additional tons for 2015 and expects continued demand for Buchanan coal throughout the year. CONSOL Energy expects to ship approximately 75% of Buchanan’s production to customers in the US and Atlantic Basin in 2015.

In the first quarter, CONSOL Energy sold 0.5 million tons of Miller Creek coal, which is flat compared to the year-earlier quarter. CONSOL Energy's total firm and priced contracted position for 2015 and for 2016 remains the same at 1.9 million tons for 2015, or 93% of estimated sales volumes based on the midpoint of guidance, and 0.9 million tons for 2016, or 41% (and sold position to 1.9 million tons, or 90%) of estimated sales volumes based on the midpoint of guidance.

CONSOL Energy also continues to benefit from its Western Allegheny Energy joint venture, as well as working closely with our marketing partner to explore global opportunities for new coal customers.

Additionally, CONSOL Energy’s wholly owned Baltimore Terminal had a strong quarter by shipping 3.5 million net tons, which also included third-party tons.

CONSOL Energy 2015 - 2016 Guidance

Second quarter 2015 gas production, net to CONSOL Energy, is expected to be approximately 71 – 75 Bcfe, while annual 2015 production guidance remains between 300 – 310 Bcfe, or 30% growth compared to 2014 total production. CONSOL Energy expects 2015 production to be more back-end weighted throughout the year due to the turn in-line schedule. CONSOL Energy continues to expect 2016 annual gas production to grow by 20%.

Total hedged natural gas production in the 2015 second quarter is 30.2 Bcf, at an average price of $4.05 per Mcf. The annual gas hedge position for two years is shown in the table below:



	2015	2016
Total Yearly Production (Bcfe) / % growth	300-310	+20%
Volumes Hedged (Bcf), as of 4/09/15	121.2*	110.9
Average Hedge Price ($/Mcf)	$4.05	$3.97

* Includes first quarter 2015 actual settlements of 29.9 Bcf.

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



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

In the second quarter of 2015, Pennsylvania Operations sales guidance is lower due to a number of planned non-productive days resulting from longwall moves and miner vacation days. Also, Virginia Operations sales guidance is slightly lower due to scheduled shaft repair work.



	Q2 2015		2015		2016
Est. Total Coal Sales	7.1 - 7.7		30.5 - 33.0		30.5 - 33.0
Tonnage: Firm	6.7		26.8		14.5
Price: Sold (firm)	$	59.86	$	61.07	$	61.22
Est. PA Operations Sales	5.8 - 6.1		24.9 - 26.6		24.9 - 26.6
Tonnage: Firm	5.6		22.6		12.9
Est. VA Operations Sales	0.9 - 1.1		3.7 - 4.2		3.7 - 4.2
Tonnage: Firm	0.6		2.3		0.8
Est. Other Sales	0.4 - 0.5		1.9 - 2.2		1.9 - 2.2
Tonnage: Firm	0.5		1.9		0.8

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 for purposes of this table, includes a price forecast when the contracted price is based on power prices received by the customer. Firm tonnage excludes collared tons and tons that are sold but not yet priced. There are no collared tons in 2015. Collared tons in 2016 are 0.9 million tons, with a ceiling of $61.46 per ton and a floor of $57.54 per ton. Not included in the table are the tons from Western Allegheny Energy (WAE). WAE has 0.1 million tons for Q2 2015, and 0.5 million tons and 0.5 million tons for all of 2015, and 2016, respectively.

Results of Operations - Three Months Ended March 31, 2015 Compared with Three Months Ended March 31, 2014

Net Income

CONSOL Energy reported net income of $79 million, or $0.34 per diluted share, for the three months ended March 31, 2015, compared to net income of $116 million, or $0.50 per diluted share, for the three months ended March 31, 2014. The breakdown of net income is as follows:



	For the Three Months Ended March 31,
(Dollars in millions, except per share data)	2015		2014			Variance
Income from Continuing Operations	$	79	$	122		$	(43	)
Loss from Discontinued Operations, net	—		(6		)	6
Net Income	$	79	$	116		$	(37	)

Income from Continuing Operations	$	0.34	$	0.53		$	(0.19	)
Loss from Discontinued Operations	—		(0.03		)	0.03
Total Dilutive Earnings Per Share	$	0.34	$	0.50		$	(0.16	)

The total Exploration and Production (E&P) division includes Marcellus, Utica, coalbed methane (CBM), and other gas. The total E&P division contributed $76 million of earnings before income taxes for the three months ended March 31, 2015 compared to $80 million of earnings before income taxes for the three months ended March 31, 2014. Total E&P production was 71.6 Bcfe for the three months ended March 31, 2015 compared to 48.4 Bcfe for the three months ended March 31, 2014.

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



	For the Three Months Ended March 31,
in thousands (unless noted)	2015		2014			Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	6,525		1,569			4,956			315.9	%
Sales Volume (Mbbls)	1,088		262			826			315.3	%
Gross Price ($/Bbl)	$	20.40	$	47.52		$	(27.12	)	(57.1	)%
Gross Revenue	$	22,171	$	12,424		$	9,747		78.5	%

Oil:
Sales Volume (MMcfe)	144		146			(2		)	(1.4	)%
Sales Volume (Mbbls)	24		24			—			—	%
Gross Price ($/Bbl)	$	47.82	$	90.18		$	(42.36	)	(47.0	)%
Gross Revenue	$	1,149	$	2,192		$	(1,043	)	(47.6	)%

Condensate:
Sales Volume (MMcfe)	1,492		296			1,196			404.1	%
Sales Volume (Mbbls)	249		49			200			408.2	%
Gross Price ($/Bbl)	$	20.82	$	70.32		$	(49.50	)	(70.4	)%
Gross Revenue	$	5,180	$	3,469		$	1,711		49.3	%

GAS
Sales Volume (MMcf)	63,456		46,388			17,068			36.8	%
Sales Price ($/Mcf)	$	3.10	$	5.71		$	(2.61	)	(45.7	)%
Hedging Impact ($/Mcf)	$	0.48	$	(0.34	)	$	0.82		241.2	%
Gross Revenue including Hedging Impact	$	226,627	$	249,110		$	(22,483	)	(9.0	)%

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



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Average Sales Price (per Mcfe)	$	3.56	$	5.52	$	(1.96	)	(35.5	)%
Average Costs (per Mcfe)	3.05		3.63		(0.58		)	(16.0	)%
Margin	$	0.51	$	1.89	$	(1.38	)	(73.0	)%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $255 million for the three months ended March 31, 2015 compared to $267 million for the three months ended March 31, 2014. The decrease was primarily due to the 35.5% decrease in average sales price per Mcfe, offset in part, by the 48.0% increase in total volumes sold. The decrease in average sales price is the result of a decrease in general market prices. The decrease was offset, in part, by our hedging program. These economic hedges represented approximately 29.9 Bcf of our produced gas sales volumes for the three months ended March 31, 2015 at an average gain of $1.01 per Mcf. These economic hedges represented approximately 35.1 Bcf of our produced gas sales volumes for the three months ended March 31, 2014 at an average loss of $0.45 per Mcf.

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


•	The improvement in unit costs is primarily due to the 48.0% increase in gas sales volumes in the period-to-period comparison and the shift to lower cost Marcellus and Utica Shale production. Marcellus production made up 50.7% of natural gas and liquid sales volumes for the three months ended March 31, 2015 compared to 42.9% in the three months ended March 31, 2014.


•	Depreciation, depletion and amortization decreased on a unit basis due to the increase in sales volumes from our lower cost Marcellus and Utica production. The decrease was offset, in part, by an increase in total dollars as the portion of production from higher investment cost segments continued to grow.


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

The coal division is made up of the Pennsylvania Operations segment, Virginia Operations segment and Other Coal segment. The total coal division contributed $107 million of earnings before income taxes for the three months ended March 31, 2015 compared to $113 million for the three months ended March 31, 2014. The total coal division sold 8.2 million tons of coal produced from CONSOL Energy mines for the three months ended March 31, 2015 compared to 8.0 million tons for the three months ended March 31, 2014.

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



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Average Sales Price per ton sold	$	60.23	$	66.20	$	(5.97	)	(9.0	)%
Average Cost of Goods Sold per ton	43.34		45.14		(1.80		)	(4.0	)%
Margin	$	16.89	$	21.06	$	(4.17	)	(19.8	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical and domestic thermal coal markets and the oversupply of coal used in steelmaking. The coal division priced 2.9 million tons on the export market for the three months ended March 31, 2015 compared to 2.0 million tons for the three months ended March 31, 2014. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily attributable to the decrease in operating shifts at our Buchanan Mine. The mine went from three operating shifts to two operating shifts beginning in May 2014 and employed other cost cutting measures due to depressed market conditions. The decrease was offset, in part, by adverse geological conditions at the Harvey Mine and Enlow Fork Mine.

The Other division includes 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, 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 March 31,
(in millions)	2015		2014		Variance			Percent Change
Contributions	$	1	$	7	$	(6	)	(85.7	)%
Employee wages and related expenses	12		11		1			9.1	%
Advertising and Promotion	2		2		—			—	%
Consulting and professional services	5		6		(1		)	(16.7	)%
Miscellaneous	3		4		(1		)	(25.0	)%
Total Company General and Administrative Expense	$	23	$	30	$	(7	)	(23.3	)%

Overall, total Company General and Administrative Expenses have decreased $7 million in the period-to-period comparison. This was primarily due to a contingent charitable contribution agreement with the Boy Scouts of America entered into in 2010. The final $6 million of the contribution was recognized during the three months ended March 31, 2014. The remaining $1 million improvement was due to various transactions that occurred throughout both periods, none of which were individually material.

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. In general, the expenses are then allocated to operational units based on active employee counts or active salary dollars. The allocation of OPEB and Pension expense in relation to the Coal Division has changed to a methodology more in-line with the structural changes the company is currently in the process of making. The amounts are also no longer included in unit costs because the majority of the contributing employees are no longer active employees. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $12 million for the three months ended March 31, 2015 compared to $28 million for the three months ended March 31, 2014. The decrease of $16 million for total Company expense was primarily due to modifications made to the OPEB and Pension plans in the year ended December 31, 2014. See Note 16 - Pension and Other Postretirement Benefits Plans and Note 17 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Financial Statements in our December 31, 2014 Form 10-K for additional details.

TOTAL E&P DIVISION ANALYSIS for the three months ended March 31, 2015 compared to the three months ended March 31, 2014:

The E&P division contributed $76 million to earnings before income taxes for the three months ended March 31, 2015 compared to $80 million in the three months ended March 31, 2014. Variances by individual E&P segment are discussed below.



	For the Three Months Ended											Difference to Three Months Ended
	March 31, 2015											March 31, 2014
(in millions)	Marcellus		Utica			CBM		Other Gas		Total E&P		Marcellus			Utica			CBM			Other Gas			Total E&P
Sales:
Produced	$	137	$	19		$	75	$	23	$	254	$	12		$	12		$	(20	)	$	(15	)	$	(11	)
Related Party	—		—			1		—		1		—			—			(1		)	—			(1		)
Total Outside Sales	137		19			76		23		255		12			12			(21		)	(15		)	(12		)
Unrealized Gain on Commodity Derivative Instruments	—		—			—		60		60		—			—			—			60			60
Gas Royalty Interest	—		—			—		15		15		—			—			—			(11		)	(11		)
Purchased Gas	—		—			—		3		3		—			—			—			(1		)	(1		)
Other Income	—		—			—		17		17		—			—			—			(17		)	(17		)
Total Revenue and Other Income	137		19			76		118		350		12			12			(21		)	16			19
Lifting	7		7			9		9		32		(2		)	4			—			1			3
Ad Valorem, Severance, and Other Taxes	5		1			2		1		9		2			1			(1		)	(3		)	(1		)
Transportation, Gathering and Compression	40		5			26		8		79		22			4			—			(1		)	25
Gas Direct Administrative, Selling & Other	8		1			2		3		14		—			—			—			2			2
Depreciation, Depletion and Amortization	35		10			22		18		85		7			9			(1		)	(2		)	13
General & Administration	—		—			—		15		15		—			—			—			(2		)	(2		)
Gas Royalty Interest	—		—			—		13		13		—			—			—			(10		)	(10		)
Purchased Gas	—		—			—		3		3		—			—			—			—			—
Exploration and Other Costs	—		—			—		2		2		—			—			—			(1		)	(1		)
Other Corporate Expenses	—		—			—		19		19		—			—			—			(7		)	(7		)
Total Exploration and Production Costs	95		24			61		91		271		29			18			(2		)	(23		)	22
Interest Expense	—		—			—		3		3		—			—			—			1			1
Total E&P Division Costs	95		24			61		94		274		29			18			(2		)	(22		)	23
Earnings (Loss) Before Income Tax	$	42	$	(5	)	$	15	$	24	$	76	$	(17	)	$	(6	)	$	(19	)	$	38		$	(4	)

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $42 million to the total Company earnings before income taxes for the three months ended March 31, 2015 compared to $59 million of earnings before income taxes for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
	2015		2014			Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	31.6		19.2			12.4			64.6	%
NGLs Sales Volumes (Bcfe)*	4.1		1.3			2.8			215.4	%
Condensate Sales Volumes (Bcfe)*	0.6		0.2			0.4			200.0	%
Total Marcellus Sales Volumes (Bcfe)*	36.3		20.7			15.6			75.4	%

Average Sales Price - Gas (Mcf)	$	3.32	$	6.12		$	(2.80	)	(45.8	)%
Derivative Impact - Gas (Mcf)	$	0.40	$	(0.30	)	$	0.70		233.3	%
Average Sales Price - NGLs (Mcfe)*	$	4.12	$	8.33		$	(4.21	)	(50.5	)%
Average Sales Price - Condensate (Mcfe)*	$	4.80	$	12.06		$	(7.26	)	(60.2	)%

Total Average Marcellus sales (per Mcfe)	$	3.78	$	6.03		$	(2.25	)	(37.3	)%
Average Marcellus lifting costs (per Mcfe)	$	0.21	$	0.42		$	(0.21	)	(50.0	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.14	$	0.14		$	—		—	%
Average Marcellus transportation, gathering, and compression costs (per Mcfe)	$	1.09	$	0.88		$	0.21		23.9	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.23	$	0.38		$	(0.15	)	(39.5	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	0.95	$	1.36		$	(0.41	)	(30.1	)%
Total Average Marcellus costs (per Mcfe)	$	2.62	$	3.18		$	(0.56	)	(17.6	)%
Average Margin for Marcellus (per Mcfe)	$	1.16	$	2.85		$	(1.69	)	(59.3	)%

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

The Marcellus segment outside sales revenues were $137 million for the three months ended March 31, 2015 compared to $125 million for the three months ended March 31, 2014. The $12 million increase is primarily due to a 75.4% increase in total volumes sold, offset in part by a 37.3% decrease in total average sales prices in the period-to-period comparison. The increase in sales volumes is primarily due to additional wells coming on-line from our ongoing drilling program. The decrease in Marcellus total average sales price was primarily the result of the $2.80 per Mcf decrease in gas market prices, along with a $0.15 per Mcfe decrease in the uplift from natural gas liquids and condensate sales volumes due to decreasing prices. The decrease was offset, in part, by a $0.70 per Mcf increase resulting from various transactions from our hedging program. These economic hedges represented approximately 12.5 Bcf of our produced Marcellus gas sales volumes for the three months ended March 31, 2015 at an average gain of $1.01 per Mcf. For the three months ended March 31, 2014, these economic hedges represented approximately 14.0 Bcf at an average loss of $0.42 per Mcf.

Total costs for the Marcellus segment were $95 million for the three months ended March 31, 2015 compared to $66 million for the three months ended March 31, 2014. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $7 million for the three months ended March 31, 2015 compared to $9 million for the three months ended March 31, 2014. The decrease in total dollars primarily relates to a decrease in salt water disposal costs and a decrease in costs related to wells operated by our joint-venture partners. The decrease in unit costs was primarily due to the 75.4% increase in total sales volumes.

•Marcellus ad valorem, severance and other taxes were $5 million for the three months ended March 31, 2015 compared to $3 million for the three months ended March 31, 2014. The increase in total dollars was primarily due to an increase in severance tax expense caused by the 75.4% increase in total sales volumes and the mix of volumes by state.

•Marcellus transportation, gathering, and compression costs were $40 million for the three months ended March 31, 2015 compared to $18 million for the three months ended March 31, 2014. The increase in total dollars primarily relates to an increase in the CONE gathering fee due to the increase in gas sales volumes (See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information), an increase in processing fees associated with natural gas liquids primarily due to the 215.4% increase in NGLs sales volumes, and an increase in utilized firm transportation expense. The increase in unit costs due to the increase in total dollars was offset, in part, by the increase in gas sales volumes.

•Marcellus direct administrative, selling and other costs were $8 million for the three months ended March 31, 2015 and March 31, 2014. Direct administrative, selling and other costs attributable to the total E&P division are allocated to the individual E&P segments based on a combination of capital, production and employee counts. Unit costs were positively impacted by the increase in gas sales volumes.

•Depreciation, depletion and amortization costs were $35 million for the three months ended March 31, 2015 compared to $28 million for the three months ended March 31, 2014. There was approximately $34 million, or $0.94 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 March 31, 2015. There was approximately $27 million, or $1.33 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 March 31, 2014. There was approximately $1 million, or $0.01 per Mcfe, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended March 31, 2015, There was approximately $1 million, or $0.03 per Mcfe, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended March 31, 2014.

UTICA GAS SEGMENT

The Utica segment had a loss before income taxes of $5 million for the three months ended March 31, 2015 compared to earnings before income taxes of $1 million for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
	2015			2014			Variance			Percent Change
Utica Gas Sales Volumes (Bcf)	6.2			0.8			5.4			675.0	%
NGLs Sales Volumes (Bcfe)*	2.4			0.3			2.1			700.0	%
Condensate Sales Volumes (Bcfe)*	0.9			0.1			0.8			800.0	%
Total Utica Sales Volumes (Bcfe)*	9.5			1.2			8.3			691.7	%

Average Sales Price - Gas (Mcf)	$	1.75		$	5.32		$	(3.57	)	(67.1	)%
Derivative Impact - Gas (Mcf)	$	—		$	(0.13	)	$	0.13		100.0	%
Average Sales Price - NGLs (Mcfe)*	$	2.16		$	5.62		$	(3.46	)	(61.6	)%
Average Sales Price - Condensate (Mcfe)*	$	2.58		$	11.24		$	(8.66	)	(77.0	)%

Total Average Utica sales price (per Mcfe)	$	1.95		$	6.00		$	(4.05	)	(67.5	)%
Average Utica lifting costs (per Mcfe)	$	0.69		$	2.39		$	(1.70	)	(71.1	)%
Average Utica ad valorem, severance, and other taxes (per Mcfe)	$	0.07		$	0.39		$	(0.32	)	(82.1	)%
Average Utica transportation, gathering, and compression costs (per Mcfe)	$	0.49		$	0.45		$	0.04		8.9	%
Average Utica direct administrative, selling & other costs (per Mcfe)	$	0.16		$	0.75		$	(0.59	)	(78.7	)%
Average Utica depreciation, depletion and amortization costs (per Mcfe)	$	1.07		$	1.56		$	(0.49	)	(31.4	)%
Total Average Utica costs (per Mcfe)	$	2.48		$	5.54		$	(3.06	)	(55.2	)%
Average Margin for Utica (per Mcfe)	$	(0.53	)	$	0.46		$	(0.99	)	(215.2	)%

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

Utica outside sales revenues were $19 million for the three months ended March 31, 2015 compared to $7 million for the three months ended March 31, 2014. The increase was primarily due to the 691.7% increase in total volumes sold and was offset,

in part, by the 67.5% decrease in the total average sales price. The 8.3 Bcfe increase in total volumes sold was primarily due to additional wells coming on-line from our ongoing drilling program which is currently focused on Marcellus and Utica production. The decrease in Utica total average sales price was primarily the result of a $3.57 per Mcf decrease in average market prices. None of our produced Utica sales volumes were hedged for the three months ended March 31, 2015, which improved our average sales price $0.13 per Mcf when compared to the three months ended March 31, 2014. Economic hedges represented approximately 0.4 Bcf of produced Utica gas sales volumes at an average loss of $0.26 per Mcf for the three months ended March 31, 2014.

Total costs for the Utica segment were $24 million for the three months ended March 31, 2015 compared to $6 million for the three months ended March 31, 2014. The increase in total dollars and decrease in unit costs were all directly related to the 691.7% increase in total volumes sold, thus a per unit analysis of the Utica segment is not meaningful.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $15 million to the total Company earnings before income taxes for the three months ended March 31, 2015 compared to $34 million for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
	2015		2014			Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	18.9		19.8			(0.9		)	(4.5	)%

Average Sales Price - Gas (Mcf)	$	3.28	$	5.31		$	(2.03	)	(38.2	)%
Derivative Impact - Gas (Mcf)	$	0.72	$	(0.41	)	$	1.13		275.6	%

Total Average CBM sales price (per Mcf)	$	4.00	$	4.90		$	(0.90	)	(18.4	)%
Average CBM lifting costs (per Mcf)	$	0.50	$	0.47		$	0.03		6.4	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.11	$	0.18		$	(0.07	)	(38.9	)%
Average CBM transportation, gathering, and compression costs (per Mcfe)	$	1.37	$	1.30		$	0.07		5.4	%
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)	$	1.11	$	1.14		$	(0.03	)	(2.6	)%
Total Average CBM costs (per Mcf)	$	3.22	$	3.20		$	0.02		0.6	%
Average Margin for CBM (per Mcf)	$	0.78	$	1.70		$	(0.92	)	(54.1	)%

CBM outside sales revenues were $76 million in the three months ended March 31, 2015 compared to $97 million for the three months ended March 31, 2014. The $21 million decrease was primarily due to a 18.4% decrease in the total average sales price per Mcf as well as a 4.5% decrease in total volumes sold. The decrease in volumes sold was primarily due to normal well declines without a corresponding offset of additional wells drilled since the Company's current focus is on Marcellus and Utica production. The CBM total average sales price decreased $0.90 per Mcf due to a $2.03 per Mcf decrease in gas market prices. The decrease was offset, in part, by a $1.13 per Mcf increase due to various transactions from our hedging program. These economic hedges represented approximately 13.2 Bcf of our produced CBM gas sales volumes for the three months ended March 31, 2015 at an average gain of $1.04 per Mcf. For the three months ended March 31, 2014, these economic hedges represented approximately 16.7 Bcf at an average loss of $0.49 per Mcf.

Total costs for the CBM segment were $61 million for the three months ended March 31, 2015 compared to $63 million for the three months ended March 31, 2014. The decrease in total dollars and increase in unit costs for the CBM segment were due to the following items:

•CBM lifting costs were $9 million for the three months ended March 31, 2015 and March 31, 2014. The increase in unit costs was due to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $2 million for the three months ended March 31, 2015 compared to $3 million for the three months ended March 31, 2014. The decrease of $1 million was due to a decrease in severance tax expense resulting from the decrease in average sales price, without the impact of hedging, as described above. Unit costs were also positively impacted by the decrease in average sales price which was offset, in part, by the decrease in gas sales volumes.

•CBM transportation, gathering, and compression costs were $26 million for the three months ended March 31, 2015 and March 31, 2014. Unit costs were negatively impacted by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $2 million for the three months ended March 31, 2015 and March 31, 2014. 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 March 31, 2015 compared to $23 million for the three months ended March 31, 2014. There was approximately $14 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 March 31, 2015. The production portion of depreciation, depletion and amortization was $16 million, or $0.78 per unit-of-production in the three months ended March 31, 2014. There was approximately $8 million, or $0.38 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended March 31, 2015. The non-production related depreciation, depletion and amortization was $7 million, or $0.36 per Mcf for the three months ended March 31, 2014.

OTHER GAS SEGMENT

The other gas segment contributed $24 million to the total Company earnings before income taxes for the three months ended March 31, 2015 compared to a loss before income taxes of $14 million for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
	2015			2014			Variance			Percent Change
Other Gas Sales Volumes (Bcf)	6.8			6.6			0.2			3.0	%
Oil Sales Volumes (Bcfe)*	0.1			0.1			—			—	%
Total Other Sales Volumes (Bcfe)*	6.9			6.7			0.2			3.0	%

Average Sales Price - Gas (Mcf)	$	2.77		$	5.79		$	(3.02	)	(52.2	)%
Derivative Impact - Gas (Mcf)	$	0.57		$	(0.29	)	$	0.86		296.6	%
Average Sales Price - Oil (Mcfe)*	$	8.04		$	14.48		$	(6.44	)	(44.5	)%

Total Average Other sales price (per Mcfe)	$	3.42		$	5.70		$	(2.28	)	(40.0	)%
Average Other lifting costs (per Mcfe)	$	1.17		$	1.26		$	(0.09	)	(7.1	)%
Average Other ad valorem, severance, and other taxes (per Mcfe)	$	0.22		$	0.48		$	(0.26	)	(54.2	)%
Average Other transportation, gathering, and compression costs (per Mcfe)	$	1.23		$	1.40		$	(0.17	)	(12.1	)%
Average Other direct administrative, selling & other costs (per Mcfe)	$	0.34		$	0.10		$	0.24		240.0	%
Average Other depreciation, depletion and amortization costs (per Mcfe)	$	2.64		$	2.72		$	(0.08	)	(2.9	)%
Total Average Other costs (per Mcfe)	$	5.60		$	5.96		$	(0.36	)	(6.0	)%
Average Margin for Other (per Mcfe)	$	(2.18	)	$	(0.26	)	$	(1.92	)	(738.5	)%

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

The other gas segment includes activity not assigned to the Marcellus, Utica, or CBM segments. This segment includes purchased gas activity, 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 shallow oil and gas production as well as Upper Devonian Shale in Pennsylvania and West Virginia. Outside sales revenue from the other gas segment was approximately $23 million for three months ended March 31, 2015 compared to $38 million for the three months ended March 31, 2014. The decrease in outside sales revenue primarily relates to the $2.28 decrease in total average sales price. Total costs related to these other sales were $39 million for the three months ended March 31, 2015 compared to $42 million for the three months ended March 31, 2014.

Unrealized gains on commodity derivative instruments represent changes in fair value of all existing gas commodity hedges on a mark-to-market basis. Unrealized gains on commodity derivative instruments increased $60 million due to the December 31, 2014 de-designation of all our derivative positions as hedging instruments. Changes in fair value were recorded in Accumulated Other Comprehensive Income prior to de-designation.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P division. Royalty interest gas sales revenue was $15 million for the three months ended March 31, 2015 compared to $26 million for the three months ended March 31, 2014. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period decrease.



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	5.4		4.2		1.2			28.6	%
Average Sales Price Per thousand cubic feet	$	2.76	$	6.33	$	(3.57	)	(56.4	)%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $3 million for the three months ended March 31, 2015 compared to $4 million for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.7		0.4		0.3			75.0	%
Average Sales Price Per thousand cubic feet	$	4.81	$	9.67	$	(4.86	)	(50.3	)%

Other income was $17 million for the three months ended March 31, 2015 compared to $34 million for the three months ended March 31, 2014. The $17 million change was primarily due to the following items:



	For the Three Months Ended March 31,
(in millions)	2015		2014		Variance			Percent Change
Gathering Revenue	$	6	$	19	$	(13	)	(68.4	)%
Gain on Sale of Assets	1		3		(2		)	(66.7	)%
Equity in Earnings of Affiliates	8		6		2			33.3	%
Other	2		6		(4		)	(66.7	)%
Total Other Income	$	17	$	34	$	(17	)	(50.0	)%


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


•	Gain on sale of assets decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually significant.


•	Earnings from our equity affiliates increased $2 million primarily due to an increase in earnings from CONE Midstream Partners, LP. and CONE Gathering, LLC. See Note 17 - Related Party Transactions of the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information.


•	The remaining $4 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 division based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $15 million for the three months ended March 31, 2015 compared to $17 million for the three months ended March 31, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income" 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 division. Royalty interest gas costs were $13 million for the three months ended March 31, 2015 compared to $23 million for the three months ended March 31, 2014. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	5.4		4.2		1.2			28.6	%
Average Cost Per thousand cubic feet sold	$	2.44	$	5.49	$	(3.05	)	(55.6	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $3 million for the three months ended March 31, 2015 and March 31, 2014.



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.4		0.3			75.0	%
Average Cost Per thousand cubic feet sold	$	3.96	$	8.12	$	(4.16	)	(51.2	)%

Exploration and other costs were $2 million for the three months ended March 31, 2015 compared to $3 million for the three months ended March 31, 2014. The $1 million decrease is due to the following items:



	For the Three Months Ended March 31,
(in millions)	2015		2014		Variance			Percent Change
Land Rentals	$	1	$	1	$	—		—	%
Lease Expiration Costs	1		1		—			—	%
Other	—		1		(1		)	(100.0	)%
Total Exploration and Other Costs	$	2	$	3	$	(1	)	(33.3	)%


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


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


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

Other corporate expenses were $19 million for the three months ended March 31, 2015 compared to $26 million for the three months ended March 31, 2014. The $7 million decrease in the period-to-period comparison was made up of the following items:



	For the Three Months Ended March 31,
(in millions)	2015		2014		Variance			Percent Change
Short-Term Incentive Compensation	$	1	$	6	$	(5	)	(83.3	)%
Stock-Based Compensation	4		6		(2		)	(33.3	)%
Bank Fees	—		2		(2		)	(100.0	)%
Unutilized Firm Transportation and Processing Fees	10		10		—			—	%
Other	4		2		2			100.0	%
Total Other Corporate Expenses	$	19	$	26	$	(7	)	(26.9	)%


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


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


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


•	Unutilized firm transportation costs represent pipeline transportation capacity the E&P division has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. Unutilized firm transportation and processing fees remained consistent in the period-to-period comparison.


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

Interest expense related to the E&P division was $3 million for the three months ended March 31, 2015 compared to $2 million for the three months ended March 31, 2014. Interest expense was incurred by the other gas segment on interest allocated to the E&P division under CONSOL Energy's credit facility, and a capital lease.

TOTAL COAL DIVISION ANALYSIS for the three months ended March 31, 2015 compared to the three months ended March 31, 2014:

The coal division contributed $107 million of earnings before income tax for the three months ended March 31, 2015 compared to $113 million for the three months ended March 31, 2014. Variances by the individual coal segment are discussed below.



	For the Three Months Ended										Difference to Three Months Ended
	March 31, 2015										March 31, 2014
(in millions)	Pennsylvania Operations			Virginia Operations		Other Coal			Total Coal		Pennsylvania Operations			Virginia Operations			Other Coal			Total Coal
Sales:
Produced Coal	$	384		$	81	$	30		$	495	$	(28	)	$	(3	)	$	(5	)	$	(36	)
Purchased Coal	—			—		2			2		—			—			(2		)	(2		)
Total Coal Sales	384			81		32			497		(28		)	(3		)	(7		)	(38		)
Other Outside Sales	—			—		13			13		—			—			3			3
Freight Revenue	2			—		5			7		(5		)	—			2			(3		)
Miscellaneous Other Income	2			—		18			20		—			—			(7		)	(7		)
Gain on Sale of Assets	—			—		1			1		(1		)	—			1			—
Total Revenue and Other Income	388			81		69			538		(34		)	(3		)	(8		)	(45		)
Cost of Coal Sold:
Operating Costs	217			36		20			273		18			(20		)	(7		)	(9		)
Direct Administrative and Selling	6			1		1			8		(1		)	(1		)	—			(2		)
Total Royalty/Production Taxes	14			5		3			22		(4		)	—			—			(4		)
Depreciation, Depletion and Amortization	42			9		2			53		9			(1		)	1			9
Total Cost of Coal Sold:	279			51		26			356		22			(22		)	(6		)	(6		)
Other Costs and Expenses:
Other Costs	(4		)	—		43			39		(7		)	(2		)	(3		)	(12		)
Direct Administrative and Selling	—			—		1			1		(1		)	—			—			(1		)
Depreciation, Depletion and Amortization	3			3		6			12		1			1			(3		)	(1		)
Total Other Costs and Expenses:	(1		)	3		50			52		(7		)	(1		)	(6		)	(14		)
General and Administrative Expense	5			1		1			7		(1		)	(1		)	(4		)	(6		)
Other Corporate Expense	5			3		1			9		(8		)	(1		)	(1		)	(10		)
Freight Expense	2			—		5			7		(5		)	—			2			(3		)
Total Costs	290			58		83			431		1			(25		)	(15		)	(39		)
Earnings (Loss) Before Income Taxes	$	98		$	23	$	(14	)	$	107	$	(35	)	$	22		$	7		$	(6	)

PENNSYLVANIA (PA) OPERATIONS COAL SEGMENT

The PA Operations coal segment's principal activities are mining, preparation and marketing of thermal coal to power generators. The segment also includes general and administrative activities as well as various other activities assigned to the PA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the three months ended March 31, 2015 and 2014 the segment included the following mines: Bailey Mine, Enlow Fork Mine, Harvey Mine and the corresponding preparation plant facilities.

The PA Operations coal segment contributed $98 million to total Company earnings before income taxes for the three months ended March 31, 2015 and $133 million of earnings before income taxes for the three months ended March 31, 2014. PA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Company Produced PA Operations Tons Sold (in millions)	6.5		6.4		0.1			1.6	%
Average Sales Price Per PA Operations Ton Sold	$	58.82	$	64.66	$	(5.84	)	(9.0	)%

Total Operating Costs Per Ton Sold	$	33.08	$	31.20	$	1.88		6.0	%
Total Direct Administration and Selling Costs Per Ton Sold	0.98		1.16		(0.18		)	(15.5	)%
Total Royalty/Production Taxes Per Ton Sold	2.18		2.85		(0.67		)	(23.5	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	6.49		5.08		1.41			27.8	%
Total Costs Per PA Operations Ton Sold	$	42.73	$	40.29	$	2.44		6.1	%
Average Margin Per PA Operations Ton Sold	$	16.09	$	24.37	$	(8.28	)	(34.0	)%

Coal Sales

PA Operations coal outside sales revenues were $384 million for the three months ended March 31, 2015 compared to $412 million for the three months ended March 31, 2014. The $28 million decrease was attributable to a $5.84 per ton lower average sales price. The decrease in average sales price per PA Operations ton sold in the 2015 period was primarily the result of the overall decline in the domestic thermal coal markets. The PA Operations coal segment revenue was also impacted by 2.0 million tons of PA Operations coal being priced on the export market for the three months ended March 31, 2015, which was 0.9 million tons higher than the tons sold for the three months ended March 31, 2014.

Freight Revenue

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $2 million for the three months ended March 31, 2015 compared to $7 million for the three months ended March 31, 2014. The $5 million decrease in freight revenue was due to decreased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

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

Gain on Sale of Assets

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

Cost of Coal Sold

Cost of coal sold is comprised of operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The costs of coal sold per ton include items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion, and amortization costs. Total cost of coal sold for PA Operations were $279 million for the three months ended March 31, 2015, or $22 million higher than the

$257 million for the three months ended March 31, 2014. Total costs per PA Operations ton sold was $42.73 per ton for the three months ended March 31, 2015 compared to $40.29 per ton for the three months ended March 31, 2014. The increase in total dollars and unit costs was primarily due to adverse geological conditions at the Harvey mine and Enlow Fork mine, primarily relating to sandstone intrusions. The result was reduced coal production and higher maintenance costs at both mines.

Other Costs And Expenses

Other costs is comprised of various costs and expenses that are assigned to the PA Operations coal segment, but not allocated to each individual mine and therefore not included in unit costs. Other costs, including certain administrative expense and depreciation, depletion, and amortization, decreased $7 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily related to the $5 million actuarially-calculated amortization due to modifications made to the Pension and OPEB plans in September 2014. Refer to the discussion of total Company long-term liabilities for continuing operation contained in the section "Net Income" of this quarterly report for more information. The remaining $2 million decrease is due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and Administrative costs are allocated to each coal segment based upon the activity at the segment determined by their level of operating activity. The amount of General and Administrative costs allocated to PA Operations was $5 million for the three months ended March 31, 2015 compared to $6 million for the three months ended March 31, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

Other corporate expense is made up of expenses for stock based compensation and the short-term incentive compensation program. These expenses are made up of costs that are directly related to each coal segment along with a portion of costs that are allocated to each segment based on a percent of total labor dollars. For the three months ended March 31, 2015 other corporate expenses were $5 million compared to $13 million for the three months ended March 31, 2014. The decrease of $8 million was primarily due to lower short-term incentive compensation payouts.

Freight Expense

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. For the three months ended March 31, 2015 freight expense was $2 million compared to $7 million for the three months ended March 31, 2014. The $5 million decrease was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

VIRGINIA (VA) OPERATIONS COAL SEGMENT

The VA Operations coal segment's principal activities are mining, preparation and marketing of low volatile metallurgical coal to metal and coke producers. The segment also includes general and administrative activities as well as various other activities assigned to the VA Operations coal segment but not allocated to each individual mine and are therefore not included in unit cost presentation. For the three months ended March 31, 2015 and 2014 the segment included Buchanan Mine and the corresponding preparation plant facilities.

The VA Operations coal segment contributed $23 million to total Company earnings before income taxes for the three months ended March 31, 2015 compared to earnings before income taxes of $1 million for the three months ended March 31, 2014. The VA Operations coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Company Produced VA Operations Tons Sold (in millions)	1.2		1.1		0.1			9.1	%
Average Sales Price Per VA Operations Ton Sold	$	67.47	$	76.80	$	(9.33	)	(12.1	)%

Total Operating Costs Per Ton Sold	$	30.37	$	51.77	$	(21.40	)	(41.3	)%
Total Direct Administration and Selling Costs Per Ton Sold	0.93		1.50		(0.57		)	(38.0	)%
Total Royalty/Production Taxes Per Ton Sold	3.92		4.57		(0.65		)	(14.2	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	7.09		8.57		(1.48		)	(17.3	)%
Total Costs Per VA Operations Ton Sold	$	42.31	$	66.41	$	(24.10	)	(36.3	)%
Average Margin Per VA Operations Ton Sold	$	25.16	$	10.39	$	14.77		142.2	%

Coal Sales

VA Operations coal outside sales revenues were $81 million for the three months ended March 31, 2015 compared to $84 million for the three months ended March 31, 2014. Average sales price per VA Operations ton sold decreased $9.33 per ton in the period-to-period comparison due to the weakening in the global metallurgical coal market. The VA Operations coal segment revenue was also impacted by 0.9 million tons of VA Operations coal being priced on the export market for the three months ended March 31, 2015 and March 31, 2014.

Cost of Coal Sold

Total cost of coal sold for VA Operations was $51 million for the three months ended March 31, 2015, or $22 million lower than the $73 million for the three months ended March 31, 2014. Total costs per VA Operations ton sold were $42.31 per ton in the three months ended March 31, 2015 compared to $66.41 per ton for the three months ended March 31, 2014. The decrease in total dollars and unit costs per VA Operations ton sold was primarily due to a modification of the operating shifts at the Buchanan Mine and other cost control measures that were implemented due to the weak metallurgical coal market. The mine went from three operating shifts to two operating shifts beginning in May 2014, which resulted in lower wage and wage related expenses, maintenance and supply costs and a reduction in the number of degas wells drilled.

Other Costs And Expenses

Other costs, including certain administrative expense and depreciation, depletion, and amortization, decreased $1 million for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and Administrative costs allocated to the VA Operations coal segment were $1 million for the three months ended March 31, 2015 and $2 million for the three months ended March 31, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

For the three months ended March 31, 2015 other corporate expenses were $3 million compared to $4 million for the three months ended March 31, 2014. The decrease of $1 million was primarily due to lower short-term incentive compensation payouts.

OTHER COAL SEGMENT

The other coal segment primarily includes coal terminal operations, idle mine activities and purchased coal activities as well as various other activities not assigned to either PA Operations or VA Operations. The other coal segment also includes activities related to mining, preparation and marketing of thermal coal to power generators geographically separated from PA Operations. For the three months ended March 31, 2015 and 2014, the segment included the Miller Creek Complex.

The other coal segment had a loss before income taxes of $14 million for the three months ended March 31, 2015 compared to a loss before income taxes of $21 million for the three months ended March 31, 2014. Other coal revenue and cost components on a per unit basis for these periods were as follows:



	For the Three Months Ended March 31,
	2015		2014		Variance			Percent Change
Company Produced Other Operations Tons Sold (in millions)	0.5		0.5		—			—	%
Average Sales Price Per Other Operations Ton Sold	$	61.54	$	62.90	$	(1.36	)	(2.2	)%

Total Operating Costs Per Ton Sold	$	45.19	$	49.22	$	(4.03	)	(8.2	)%
Total Direct Administration and Selling Costs Per Ton Sold	0.88		1.23		(0.35		)	(28.5	)%
Total Royalty/Production Taxes Per Ton Sold	5.14		5.38		(0.24		)	(4.5	)%
Total Depreciation, Depletion and Amortization Costs Per Ton Sold	2.95		3.46		(0.51		)	(14.7	)%
Total Costs Per Other Operations Ton Sold	$	54.16	$	59.29	$	(5.13	)	(8.7	)%
Average Margin Per Other Operations Ton Sold	$	7.38	$	3.61	$	3.77		104.4	%

Coal Sales

Other coal outside sales revenues were $30 million for the three months ended March 31, 2015 compared to $35 million for the three months ended March 31, 2014. The $5 million decrease was attributable to a $1.36 per ton lower average sales price. The lower average coal sales price in the 2015 period was the result of the overall decline in the domestic thermal coal markets.

Purchased coal sales consisted of revenues from coal purchased from third parties and sold directly to our customers. The revenues were $2 million for the three months ended March 31, 2015 compared to $4 million for the three months ended March 31, 2014. The $2 million decrease in the period-to-period comparison was due to lower volumes of coal that needed to be purchased to fulfill various contracts.

Other Outside Sales Revenue

Other outside sales revenue for the Other coal segment consist of revenues from our coal terminal operations. Coal terminal operations sales revenues increased $3 million in the period-to-period comparison primarily due to an increase in thru-put volumes in the current quarter.

Freight Revenue

Freight revenue was $5 million for the three months ended March 31, 2015 compared to $3 million for the three months ended March 31, 2014. The $2 million increase in freight revenue was due to increased shipments where CONSOL Energy contractually provides transportation services.

Miscellaneous Other Income

Miscellaneous other income was $18 million for the three months ended March 31, 2015 compared to $25 million for the three months ended March 31, 2014. The change is due to the following items:



	For the Three Months Ended March 31,
(in millions)	2015		2014		Variance
Rental Income	$	9	$	14	$	(5	)
Royalty Income	4		5		(1		)
Equity in earnings of affiliates	3		3		—
Other	2		3		(1		)
Total Other Income	$	18	$	25	$	(7	)


•	Rental income decreased $5 million due to more equipment leased and equipment subleased to a third-party in 2014.


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


•	Equity in earnings of affiliates remained consistent in the period-to-period comparison.


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

Gain on Sale of Assets

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

Cost of Coal Sold

Total cost of coal sold for Other Operations was $26 million for the three months ended March 31, 2015, or $6 million lower than the $32 million for the three months ended March 31, 2014. Total costs per Other Operations ton sold were $54.16 per ton for the three months ended March 31, 2015 compared to $59.29 per ton for the three months ended March 31, 2014. The decrease in total dollars and unit costs was primarily due to lower wages and wage related expenses and lower maintenance and supply costs.

Other Costs And Expenses

Other costs and expenses related to the Other coal segment were $50 million for the three months ended March 31, 2015 compared to $56 million for the three months ended March 31, 2014. The decrease of $6 million was due to the following items:



	For the Three Months Ended March 31,
	2015		2014		Variance
Purchased Coal	$	1	$	6	$	(5	)
Depreciation, Depletion & Amortization	6		9		(3		)
Lease Rental Expense	7		9		(2		)
Coal Terminal Operations	6		7		(1		)
Closed and Idle Mines	14		14		—
Coal Reserve Holding Costs	2		2		—
Pension and OPEB Plan	8		—		8
Other	6		9		(3		)
Total Other Costs	$	50	$	56	$	(6	)


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


•	Depreciation, depletion, and amortization decreased $3 million primarily due to fewer assets placed in service in the period-to-period comparison.


•	Lease rental expense decreased $2 million primarily due to fewer equipment leases that were subleased to a third-party in 2015.


•	Coal terminal operations costs decreased $1 million due to decreased thru-put volumes in the current quarter.


•	Pension and OPEB plan expense of $8 million is the actuarially-calculated amortization due to modifications made to the Pension and OPEB plans in September 2014. Refer to the discussion of total Company long-term liabilities for continuing operations contained in the section "Net Income" of this quarterly report for more information.


•	Other decreased $3 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

General and Administrative Expense

General and Administrative costs allocated to the Other coal segment were $1 million for the three months ended March 31, 2015 compared to $5 million for the three months ended March 31, 2014. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income" of this quarterly report for a detailed cost explanation.

Other Corporate Expense

Other corporate expenses were $1 million for the three months ended March 31, 2015 compared to $2 million for the three months ended March 31, 2014. The $1 million decrease was primarily due to lower short-term incentive compensation payouts.

Freight Expense

Freight expense was $5 million for the three months ended March 31, 2015 compared to $3 million for the three months ended March 31, 2014. The increase of $2 million was primarily due to increased shipments under contracts which CONSOL Energy contractually provides transportation services.

OTHER DIVISION ANALYSIS for the three months ended March 31, 2015 compared to the three months ended March 31, 2014:

The other division includes expenses from various other corporate activities that are not allocated to the E&P or coal divisions. The other division had a loss before income taxes of $129 million for the three months ended March 31, 2015 compared to a loss before income taxes of $58 million for the three months ended March 31, 2014. The other division also includes a total Company income tax benefit of $26 million for the three months ended March 31, 2015 compared to income tax expense of $8 million for the three months ended March 31, 2014.



	For the Three Months Ended March 31,
(in millions)	2015			2014			Variance			Percent Change
Sales—Outside	$	1		$	58		$	(57	)	(98.3	)%
Other Income	—			1			(1		)	(100.0	)%
Total Revenue	1			59			(58		)	(98.3	)%
Miscellaneous Operating Expense	10			67			(57		)	(85.1	)%
Depreciation, Depletion & Amortization	—			1			(1		)	(100.0	)%
Loss on Debt Extinguishment	68			—			68			100.0	%
Interest Expense	52			49			3			6.1	%
Total Costs	130			117			13			11.1	%
Loss Before Income Tax	(129		)	(58		)	(71		)	(122.4	)%
Income Tax	(26		)	8			(34		)	(425.0	)%
Net Loss	$	(103	)	$	(66	)	$	(37	)	(56.1	)%

Outside sales revenues from the other division were $1 million for the three months ended March 31, 2015 compared to $58 million for the three months ended March 31, 2014. The decrease of $57 million was primarily related to the divestiture of our industrial supplies subsidiary in December 2014.

There was no Other Income recognized for the three months ended March 31, 2015 compared to $1 million of Other Income for the three months ended March 31, 2014. The decrease was due to various transactions that occurred throughout both periods, none of which were individually material.

Total other costs related to the other division were $130 million for the three months ended March 31, 2015 compared to $117 million for the three months ended March 31, 2014. Other costs increased due to the following items:



	For the Three Months Ended March 31,
(in millions)	2015		2014		Variance
Loss on Extinguishment of Debt	$	68	$	—	$	68
Pension Expense	5		—		5
Interest Expense	52		49		3
Bank Fees	4		4		—
Industrial Supplies	—		58		(58		)
Other	1		6		(5		)
	$	130	$	117	$	13

•

Loss on Extinguishment of Debt of $68 million was recognized in the three months ended March 31, 2015 related to the early extinguishment of debt due to the partial purchase of the 8.25% senior notes that were due in 2020 at a price equal to 104.6% of the principal amount and the partial purchase of the 6.375% senior notes that were due in 2021 at a price equal to 105.0% of the principal amount. No such transactions took place in the prior period.


•	Actuarially-calculated amortization of $5 million was included in the Other Division in the three months ended March 31, 2015 due to modifications made to the Pension plan in September 2014. Refer to the discussion of total Company long-term liabilities for continuing operation contained in the section "Net Income" of this quarterly report for more information.

•

Interest expense increased $3 million in the period-to-period comparison 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 early payoff of the 2017 bonds and partial purchase of the 2020 bonds. The increase was also offset, in part, by a decrease 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.


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


•	There were no Industrial Supplies costs in the three months ended March 31, 2015 and $58 million in the three months ended March 31, 2014. The decrease is due to the divestiture of our industrial supplies subsidiary in December 2014.


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

Income Taxes:

The effective income tax rate was (47.9)% for the three months ended March 31, 2015 compared to 6.5% for the three months ended March 31, 2014. The effective rates for the three months ended March 31, 2015 and 2014 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. 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 March 31,
(in millions)	2015			2014			Variance			Percent Change
Total Company Earnings Before Income Tax	$	53		$	130		$	(77	)	(59.1	)%
Income Tax (Benefit) Expense	$	(26	)	$	8		$	(34	)	(425.0	)%
Effective Income Tax Rate	(47.9		)%	6.5		%	(54.4		)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. On June 18, 2014, CONSOL Energy entered into a Credit Agreement for a $2.0 billion senior secured revolving credit facility. This Agreement expires on June 18, 2019. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $2.0 billion of borrowings, which includes $750 million letters of credit aggregate sub-limit. CONSOL Energy can request an additional $500 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of CONSOL Energy's proved gas reserves. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 4.72 to 1.00 at March 31, 2015. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations, losses on debt extinguishment and includes cash distributions received from affiliates, plus pro-rata earnings from material acquisitions. The facility also includes a minimum current ratio covenant of no less than 1.00 to 1.00, measured quarterly. The minimum current ratio is calculated as the ratio of current assets, plus revolver availability, to current liabilities excluding borrowings under the revolver and accounts receivable securitization facility. The current ratio was 1.60 to 1.00 at March 31, 2015. Affirmative and negative covenants in the facility limit the Company's ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems. The facility permits CONSOL Energy to separate its gas and coal businesses if the leverage ratio (which, is essentially, the ratio of debt to EBITDA) of the gas business immediately after the separation would not be greater than 2.75 to 1.00. At March 31, 2015, the facility had $761 million of borrowings outstanding and $214 million of letters of credit outstanding, leaving $1,025 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. CONSOL Energy sometimes uses letters of credit to satisfy these requirements and these letters of credit reduce the Company's borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. On March 27, 2015, this facility was amended to allow the Company to receive, on a revolving basis, up to $100 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper or LIBOR rates plus a charge for administrative services paid to financial institutions. At March 31, 2015, eligible accounts receivable totaled approximately $78 million. At March 31, 2015, the borrowings outstanding totaled $33 million and $49 million of letters of credit were outstanding, leaving no unused capacity.

On March 9, 2015, CONSOL Pennsylvania Coal Company LLC and Conrhein Coal Company entered into a $600,000 commitment for a senior secured term loan facility. If drawn, the maturity date of the term loan facility is March 9, 2018. The facility is secured by the thermal coal assets related to CONSOL Energy’s existing Pennsylvania operations along with CONSOL Energy providing a guarantee to the lenders. At March 31, 2015, the term loan facility is undrawn. The term loan commitment will expire on the earlier of (1) December 31, 2015 or (2) the consummation of the CNX Coal Resources LP initial public offering. The term loan facility will contain affirmative and negative covenants that limit the ability to dispose of assets, pay dividends, merge with another corporation and incur indebtedness. The term loans shall bear interest at a rate per annum equal to LIBOR plus 3.0% a base rate plus 2.0%.

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

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap and option transactions, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $223 million at March 31, 2015. No issues related to the Company's hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Three Months Ended March 31,
	2015			2014			Change
Cash flows from operating activities	$	228		$	336		$	(108	)
Cash used in investing activities	$	(320	)	$	(335	)	$	15
Cash used in financing activities	$	(80	)	$	(14	)	$	(66	)

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


•	Net income decreased $37 million in the period-to-period comparison.


•	Adjustments to reconcile net income to cash flow provided by operating activities increased $68 million due to the loss on extinguishment of debt and additional depreciation, depletion, and amortization of $21 million. The increase was offset, in part, by a decrease of $60 million due to the unrealized gain on commodity derivative instruments


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

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


•	Capital expenditures decreased $157 million in the period-to-period comparison due to:


◦	Gas segment capital expenditures decreased $16 million. This is due to decreased expenditures in the Marcellus and Utica plays and various transactions that occurred throughout both periods.

◦

Coal segment capital expenditures decreased $143 million. This was comprised of a $95 million decrease of equipment expenditures at the Harvey Mine mainly due to the acquisition of the Harvey Mine longwall shields in 2014. Capital projects at the Harvey Mine also decreased $31 million due to its completion in the first quarter of 2014. The remaining $17 million decrease is due to various other projects that occurred throughout both periods.


◦	Other capital expenditures increased $2 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•

Proceeds from the sale of assets decreased $123 million in the period-to-period comparison primarily due to $75 million received in March 2014 related to the Harvey Mine shield sale-leaseback as well as $46 million received in January 2014 as reimbursement from Noble Energy for 50% of the Dominion Resources lease acquisition. The remaining $2 million decrease is due to various other transactions that occurred throughout both periods. See Note 2 - Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for more information.

•

Cash used by equity affiliates increased $18 million due to an additional $30 million of capital contributions to CONE Midstream Partners, LP coupled with a decrease of $8 million in capital contributions to CONE Gathering, LLC in the period ended March 31, 2015 compared to the period ended March 31, 2014. These contributions were offset in part by $4 million of additional distributions from various equity partners in the period ended March 31, 2015 compared to the period ended March 31, 2014.

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


•	In the three months ended March 31, 2015, CONSOL Energy received $761 million of proceeds from the senior secured credit facility. There were no borrowings as of March 31, 2014.


•	In the three months ended March 31, 2015, CONSOL Energy had net payments of $768 million related to the partial extinguishment of the 2020 and 2021 Bonds offset, in part, by the issuance of the 2023 bonds. See Note 11 - Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional details.


•	In the three months ended March 31, 2015, CONSOL Energy repurchased $72 million of its common stock on the open market under the previously announced share repurchase program. No repurchases were made as of March 31, 2014.


•	In the three months ended March 31, 2015, CONSOL Energy had proceeds of $33 million under the accounts receivable securitization facility. There were no borrowings under this facility as of March 31, 2014.


•	In the three months ended March 31, 2015, CONSOL Energy paid $18 million in debt issuance and financing fees related to the issuance of the 2023 bonds and other debt restructuring.


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

The following is a summary of our significant contractual obligations at March 31, 2015 (in thousands):



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase Order Firm Commitments	$	149,542	$	101,628	$	13,556	$	1,255	$	265,981
Gas Firm Transportation and Processing	114,443		212,456		184,367		625,365		1,136,631
Long-Term Debt	4,171		6,652		1,365		2,554,569		2,566,757
Interest on Long-Term Debt	191,264		325,272		324,985		452,012		1,293,533
Capital (Finance) Lease Obligations	8,166		14,435		13,466		10,953		47,020
Interest on Capital (Finance) Lease Obligations	3,028		4,429		2,650		678		10,785
Operating Lease Obligations	103,978		173,799		74,322		75,460		427,559
Long-Term Liabilities—Employee Related (a)	83,660		162,147		167,360		577,093		990,260
Other Long-Term Liabilities (b)	297,140		237,103		83,420		339,175		956,838
Total Contractual Obligations (c)	$	955,392	$	1,237,921	$	865,491	$	4,636,560	$	7,695,364

_________________________

(a)

Long-Term Liabilities - Employee Related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Additional contributions to the pension trust are not expected to be significant for the remainder of 2015.


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


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

Debt

At March 31, 2015, CONSOL Energy had total long-term debt and capital lease obligations of $2,614 billion outstanding, including the current portion of long-term debt of $13 million. This long-term debt consisted of:


•	An aggregate principal amount of $77 million of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.


•	An aggregate principal amount of $21 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.


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


•	An aggregate principal amount of $500 million of 8.00% senior unsecured notes due in April 2023 less $7 million of unamortized bond discount. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.


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


•	Advance royalty commitments of $13 million with an average interest rate of 7.91% per annum.


•	An aggregate principal amount of $4 million on other various rate notes maturing through March 2018.


•	An aggregate principal amount of $47 million of capital leases with a weighted average interest rate of 6.44% per annum.

At March 31, 2015, CONSOL Energy had an aggregate principal amount of $761 million in outstanding borrowings and approximately $214 million of letters of credit outstanding under the $2.0 billion senior secured revolving credit facility.

At March 31, 2015, CONSOL Energy had an aggregate principal amount of $33 million in outstanding borrowings and $49 million of letters of credit outstanding under the accounts receivable securitization facility.

Total Equity and Dividends

CONSOL Energy had total equity of $5.3 billion at March 31, 2015 and at December 31, 2014. 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 is as follows:



Declaration Date	Amount Per Share		Record Date	Payment Date
February 2, 2015	$	0.0625	February 17, 2015	March 5, 2015
April 29, 2015	$	0.0625	May 11, 2015	May 21, 2015

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.50 per share when our leverage ratio exceeds 3.50 to 1.00 and subject to an aggregate amount up to the then cumulative credit calculation. The total leverage ratio was 3.33 to 1.00 and our availability was approximately $515 million at March 31, 2015. The credit facility does not permit dividend payments in the event of default. The indentures to the 2022 and 2023 notes limit dividends to $0.50 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults in the three months ended March 31, 2015.

CONSOL Energy has publicly announced that if CONSOL Energy effects an initial public offering of a thermal coal MLP, CONSOL Energy anticipates that it would reduce or eliminate its current regular dividend effective in the first quarter after the initial public offering.

Off-Balance Sheet Transactions

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

Forward-Looking Statements

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


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

•

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


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


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


•	our reliance on major customers;


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


•	the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas and coal to market;


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


•	coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;


•	the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for natural gas and coal;


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


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


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


•	the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our natural gas and coal operations;


•	our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;


•	the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine;


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


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


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


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


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


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


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


•	acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made and 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 gas and oil reserves, which if not replaced, will cause our gas and oil reserves and production to decline;


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


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


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


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


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


•	operating in a single geographic area;


•	our inability to complete the initial public offering of CNX Coal Resources LP (CNXC) owning certain of our thermal coal assets or an initial public offering of the subsidiary owning certain of our metallurgical coal assets (Metco); and


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

A registration statement relating to the common units of CNXC has been filed with the Securities and Exchange Commission but has not yet become effective. The common units of CNXC may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective. This announcement does not constitute an offer to sell, or the solicitation of an offer to buy, any securities of CNXC.

A registration statement relating to the securities of Metco that would be sold in the offering has not been filed with the Securities and Exchange Commission or become effective. This announcement does not constitute an offer to sell, or the solicitation of an offer to buy, any securities of Metco.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

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

For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of CONSOL Energy's 2014 Form 10-K.

At March 31, 2015, our open derivative instruments were in a net asset position with a fair value of $223 million. A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at March 31, 2015. A hypothetical 10 percent increase in future natural gas prices would affect pre-tax future earnings related to derivatives by $56 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At March 31, 2015, CONSOL Energy had $2,614 billion aggregate principal amount of debt outstanding under fixed-rate instruments and $794 million of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were $761 million of borrowings at March 31, 2015.

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 April 13, 2015, our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2015 Fixed Price Volumes
Hedged Mcf	N/A		30,224,666		30,556,805		30,556,805		91,338,276
Weighted Average Hedge Price per Mcf	N/A		$	4.05	$	4.05	$	4.05	$	4.05
2016 Fixed Price Volumes
Hedged Mcf	27,569,465		27,569,465		27,872,426		27,872,426		110,883,782
Weighted Average Hedge Price per Mcf	$	3.97	$	3.97	$	3.97	$	3.97	$	3.97
2017 Fixed Price Volumes
Hedged Mcf	2,727,273		2,757,576		2,787,879		2,787,879		11,060,607
Weighted Average Hedge Price per Mcf	$	3.08	$	3.08	$	3.08	$	3.08	$	3.08


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 March 31, 2015 to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

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

PART II: OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

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

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

In July 2011, EPA also proposed standards under Section 316(b) of the CWA to reduce the injury and death of fish and other aquatic life caused by cooling-water intake structures at existing power plants, including coal- and natural gas-fired power plants. The proposed rule would require any covered facility either to install technologies to reduce fish mortality or reduce the facility’s intake velocity. On May 19, 2014 EPA finalized CWA Section 316(b) standards which established requirements for new and existing power generating facilities and existing manufacturing and industrial facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes.

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

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

While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs) such as carbon dioxide and methane. Combustion of fossil fuels, such as the natural gas and coal we produce, results in the creation of carbon dioxide emissions into the atmosphere by natural gas and coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Other states have elected to participate in voluntary regional cap-and-trade programs like the Regional Greenhouse Gas Initiative (RGGI) in the northeastern U.S. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (but has not been ratified by the United States, and Canada officially withdrew from its Kyoto commitment in 2012) was nominally extended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. The EPA has elected to regulate GHGs under the Clean Air Act. On January 8, 2014, EPA re-proposed NSPS for carbon dioxide (CO2) for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012. These proposed rules will also require partial carbon capture and storage (CCS) for new coal fired power plants. EPA announced it will issue the final rules for new power plants by mid-summer 2015.

Apart from governmental regulation, investment banks both domestically and internationally based have announced that they have adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of

electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants. In addition, banks have also adopted more stringent lending requirements of surface coal operations which may make it more difficult to obtain financing by coal operators.

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

In January 2015 EPA outlined a strategy for reducing methane and ozone-forming pollution form the oil and natural gas industry. This strategy includes potential requirements for emission reductions and mitigation techniques that target methane and volatile organic compounds (VOCs) that include methane. It is the current Administration’s goal to cut methane emissions from the oil and gas industry sector by 40 -45 percent from 2012 levels by 2025. The details of how EPA intends to reach the administrations goals are not currently known and so the potential impact to the oil and gas industry is difficult to ascertain. EPA is expected to introduce a methane gas emissions limit in the summer of 2015.

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

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

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

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

In response to a spill by Freedom Industries of crude 4-methylcyclohexanemethanol (MCHM) to the Elk River in January 2014, West Virginia signed into law Senate Bill 373 (also known as the Above Ground Storage Tank Act), which requires that all above ground storage tanks (ASTs) be registered with the Department of Environmental Protection (DEP) and meet additional requirements. In October 2014 WV DEP filed a Final Interpretive Rule (47CSR62) addressing initial inspection, certification and spill prevention response plan requirements. In January 2015 WV DEP proposed the final AST Rule (Rule 47 CSR 63). With approximately 4,000 impacted ASTs currently operational in West Virginia and more needed for the oil and gas production, this proposed final rule would have cost us tens of millions of dollars to meet the requirements. In March 2015 legislature passed

Senate Bill 423 which was amended Senate Bill 373 and was intended addressed some of the unforeseen and far-reaching consequences of the AST Act. While the amendments should exempt the majority of our WV ASTs from the most costly portion of the act, it’s difficult to gauge the costs until WV DEP finalizes a rule. DEP plans to redraft the proposed final rule and submit it for review in 2016.

CONSOL Energy utilizes pipelines extensively for its gas, water and coal businesses, and as such must obtain permits with associated mitigation from the Army Corps of Engineers (ACOE) for impacts to streams and wetlands that we are unable to avoid. In 2013, the EPA issued a draft report entitled Connectivity of Streams and Wetlands to Downstream Waters, which affects a proposed rulemaking that would expand the scope of the Clean Water Act (CWA) to include previously non-jurisdictional streams, wetlands, and waters, making these areas jurisdictional inter-coastal Waters of the U.S. On April 21, 2014, the EPA published the Proposed Rule - Definition of “Waters of the United States” (WoUS) Under the Clean Water Act. In February 2015 the EPA and ACOE issued a memorandum of understanding to withdraw the WoUS Interpretive Rule. In April 2015, the EPA sent a new version of its Waters of the U.S. proposal to the White House Office of Management and Budget for review which has not yet been release to the public. EPA expects to release the revised Final WoUS Rule sometime in Spring 2015. This rulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs offering little to no added environmental protection or benefit from the changes. This would only add unwarranted delays to the permitting process and extend review times even further for regulatory agencies already under resourced. These changes would also lead to additional mitigation cost and severely limit CONSOL’s ability to avoid regulated jurisdictional waters, while extending waters of the US coverage into areas that have no significant hydrologic connection to jurisdictional waters. The proposal as written does not accomplish the EPA’s goal of clarification, and has blurred the lines between what is and is not jurisdictional under the CWA.

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

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

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

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

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

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

The following table sets forth repurchases of our common stock during the first quarter of 2015:



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

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

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

ITEM 4. MINE SAFETY DISCLOSURES

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


ITEM 6.	EXHIBITS



4.1			Indenture, dated as of March 30, 2015, among CONSOL Energy Inc., the subsidiary guarantors party thereto and Well Fargo, National Association, as Trustee, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on March 30, 2015.

4.2			Registration Rights Agreement, dated as of March 30, 2015, 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 March 30, 2015.

4.3			Supplemental Indenture No. 3, dated as of March 23, 2015, to the Indenture dated as of March 9, 2011 by and among CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National Association, a national banking association, as successor trustee, with respect to the 6.375% Senior Notes due 2021.

4.4			Supplemental Indenture No. 5, dated as of March 23, 2015, to the Indenture dated as of April 1, 2010 by and among CONSOL Energy Inc., the Subsidiary Guarantors listed on the signature pages thereof and Wells Fargo Bank, National Association, a national banking association, as successor trustee, with respect to the 8.25% Senior Notes due 2020.

10.1			Letter Agreement Re: Receivables Purchase Agreement - Delinquency Ratio and Default Ratio, dated April 18, 2014.

10.2			Eleventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 23, 2014, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank.

10.3			Twelfth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 27, 2015, by and among CNX Funding Corporation, as seller, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator, and as LC Bank.

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

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

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

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

95			Mine Safety and Health Administration Safety Data.

101			Interactive Data File (Form 10-Q for the quarterly period ended March 31, 2015 furnished in XBRL).

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

SIGNATURES

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

Dated: May 5, 2015



	CONSOL ENERGY INC.

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

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

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