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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________

FORM 10-Q

__________________________________________________

(Mark One)



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

For the quarterly period ended March 31, 2014



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of April 18, 2014
Common stock, $0.01 par value		229,907,689

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three months ended March 31, 2014 and 2013.	3
	Consolidated Statements of Comprehensive Income for the three months ended March 31, 2014 and 2013.	4
	Consolidated Balance Sheets at March 31, 2014 and December 31, 2013.	5
	Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2014.	7
	Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013.	8
	Notes to Unaudited Consolidated Financial Statements	9

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

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 4.	Mine Safety Disclosures	65

ITEM 6.	Exhibits	66

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:	2014			2013
Natural Gas, NGLs and Oil Sales	$	266,298		$	167,842
Coal Sales	534,681			547,909
Other Outside Sales	69,287			68,684
Gas Royalty Interests and Purchased Gas Sales	30,219			15,562
Freight-Outside Coal	9,945			12,253
Miscellaneous Other Income	55,054			28,387
Gain on Sale of Assets	3,669			2,306
Total Revenue and Other Income	969,153			842,943
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	29,243			22,014
Transportation, Gathering and Compression	53,782			48,433
Production, Ad Valorem, and Other Fees	10,187			4,569
Direct Administrative and Selling	11,653			11,086
Depreciation, Depletion and Amortization	71,729			52,988
Exploration and Production Related Other Costs	3,099			10,489
Production Royalty Interests and Purchased Gas Costs	26,096			12,765
Other Corporate Expenses	26,164			25,393
General and Administrative	17,364			8,590
Total Exploration and Production Costs	249,317			196,327
Coal Costs
Operating and Other Costs	326,849			335,015
Royalties and Production Taxes	26,488			28,439
Direct Administrative and Selling	11,294			10,884
Depreciation, Depletion and Amortization	56,063			57,190
Freight Expense	9,945			12,253
General and Administrative Costs	12,513			9,301
Other Corporate Expenses	19,295			19,915
Total Coal Costs	462,447			472,997
Other Costs
Miscellaneous Operating Expense	74,549			123,035
General and Administrative Costs	406			423
Depreciation, Depletion and Amortization	1,324			1,400
Interest Expense	50,931			53,377
Total Other Costs	127,210			178,235
Total Costs And Expenses	838,974			847,559
Earnings (Loss) Before Income Tax	130,179			(4,616		)
Income Taxes	8,489			(892		)
Income (Loss) From Continuing Operations	121,690			(3,724		)
(Loss) Income From Discontinued Operations, net	(5,687		)	1,903
Net Income (Loss)	116,003			(1,821		)
Less: Net Income Attributable to Noncontrolling Interests	—			257
Net Income (Loss) Attributable to CONSOL Energy Shareholders	$	116,003		$	(1,564	)

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)	2014			2013
Earnings (Loss) Per Share
Basic
Income (Loss) from Continuing Operations	$	0.53		$	(0.02	)
(Loss) Income from Discontinued Operations	(0.02		)	0.01
Total Basic Earnings (Loss) Per Share	$	0.51		$	(0.01	)
Dilutive
Income (Loss) from Continuing Operations	$	0.53		$	(0.02	)
(Loss) Income from Discontinued Operations	(0.03		)	0.01
Total Dilutive Earnings (Loss) Per Share	$	0.50		$	(0.01	)

Dividends Paid Per Share	$	0.0625		$	—

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended
(Dollars in thousands)	March 31,
(Unaudited)	2014			2013
Net Income (Loss)	$	116,003		$	(1,821	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($2,985), ($28,250))	5,119			45,757
Net Decrease in the Value of Cash Flow Hedges (Net of tax: $30,856, $11,984)	(46,965		)	(18,595		)
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: ($10,951), $13,966)	16,313			(22,713		)

Other Comprehensive (Loss) Income	(25,533		)	4,449

Comprehensive Income	90,470			2,628

Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			257

Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders	$	90,470		$	2,885

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, 2014		December 31, 2013
ASSETS
Current Assets:
Cash and Cash Equivalents	$	314,087	$	327,420
Accounts and Notes Receivable:
Trade	355,606		332,574
Notes Receivable	25,909		25,861
Other Receivables	239,848		243,973
Inventories	156,185		157,914
Deferred Income Taxes	265,226		211,303
Recoverable Income Taxes	4,434		10,705
Prepaid Expenses	97,541		135,842
Total Current Assets	1,458,836		1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	13,850,618		13,578,509
Less—Accumulated Depreciation, Depletion and Amortization	4,245,627		4,136,247
Total Property, Plant and Equipment—Net	9,604,991		9,442,262
Other Assets:
Investment in Affiliates	309,125		291,675
Notes Receivable	95		125
Other	211,428		214,013
Total Other Assets	520,648		505,813
TOTAL ASSETS	$	11,584,475	$	11,393,667

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS



	(Unaudited)
(Dollars in thousands, except per share data)	March 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	506,584		$	514,580
Current Portion of Long-Term Debt	12,058			11,455
Other Accrued Liabilities	637,305			565,697
Current Liabilities of Discontinued Operations	14,400			28,239
Total Current Liabilities	1,170,347			1,119,971
Long-Term Debt:
Long-Term Debt	3,115,175			3,115,963
Capital Lease Obligations	46,166			47,596
Total Long-Term Debt	3,161,341			3,163,559
Deferred Credits and Other Liabilities:
Deferred Income Taxes	304,404			242,643
Postretirement Benefits Other Than Pensions	960,197			961,127
Pneumoconiosis Benefits	111,566			111,971
Mine Closing	320,270			320,723
Gas Well Closing	177,576			175,603
Workers’ Compensation	71,358			71,468
Salary Retirement	42,506			48,252
Reclamation	39,587			40,706
Other	133,036			131,355
Total Deferred Credits and Other Liabilities	2,160,500			2,103,848
TOTAL LIABILITIES	6,492,188			6,387,378
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,829,983 Issued and Outstanding at March 31, 2014; 229,145,736 Issued and Outstanding at December 31, 2013	2,301			2,294
Capital in Excess of Par Value	2,385,545			2,364,592
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	3,055,091			2,964,520
Accumulated Other Comprehensive Loss	(350,650		)	(325,117		)
Total CONSOL Energy Inc. Stockholders’ Equity	5,092,287			5,006,289
TOTAL LIABILITIES AND EQUITY	$	11,584,475		$	11,393,667

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY



(Dollars in thousands, except per share data)	Common Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total CONSOL Energy Inc. Stockholders’ Equity
December 31, 2013	$	2,294	$	2,364,592	$	2,964,520		$	(325,117	)	$	5,006,289
(Unaudited)
Net Income	—		—		116,003			—			116,003
Other Comprehensive Loss	—		—		—			(25,533		)	(25,533		)
Comprehensive Income (Loss)	—		—		116,003			(25,533		)	90,470
Issuance of Common Stock	7		4,969		—			—			4,976
Treasury Stock Activity	—		—		(11,081		)	—			(11,081		)
Tax Cost From Stock-Based Compensation	—		92		—			—			92
Amortization of Stock-Based Compensation Awards	—		15,892		—			—			15,892
Dividends ($0.0625 per share)	—		—		(14,351		)	—			(14,351		)
Balance at March 31, 2014	$	2,301	$	2,385,545	$	3,055,091		$	(350,650	)	$	5,092,287

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:	2014			2013
Net Income (Loss)	$	116,003		$	(1,821	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Continuing Operating Activities:
Net Loss (Income) from Discontinued Operations	5,687			(1,903		)
Depreciation, Depletion and Amortization	129,116			111,578
Stock-Based Compensation	15,892			26,069
Gain on Sale of Assets	(3,669		)	(2,176		)
Deferred Income Taxes	8,149			305
Equity in Earnings of Affiliates	(7,450		)	(4,797		)
Changes in Operating Assets:
Accounts and Notes Receivable	(22,231		)	27,137
Inventories	1,729			30,732
Prepaid Expenses	15,493			8,676
Changes in Other Assets	354			10,858
Changes in Operating Liabilities:
Accounts Payable	16,595			(26,474		)
Accrued Interest	51,233			50,307
Other Operating Liabilities	18,260			(27,755		)
Changes in Other Liabilities	3,655			6,236
Other	1,125			6,706
Net Cash Provided by Continuing Operations	349,941			213,678
Net Cash (Used in) Provided by Discontinued Operating Activities	(13,839		)	54,603
Net Cash Provided by Operating Activities	336,102			268,281
Cash Flows from Investing Activities:
Capital Expenditures	(451,009		)	(349,817		)
Change in Restricted Cash	—			48,294
Proceeds from Sales of Assets	125,528			74,623
Net Investments In Equity Affiliates	(10,000		)	(12,500		)
Net Cash Used in Investing Activities in Continuing Operations	(335,481		)	(239,400		)
Net Cash Used in Investing Activities in Discontinued Operations	—			7,858
Net Cash Used in Investing Activities	(335,481		)	(231,542		)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	(4,670		)	(27,451		)
Proceeds from Securitization Facility	—			(7,727		)
Tax Benefit from Stock-Based Compensation	92			730
Dividends Paid	(14,351		)	—
Issuance of Common Stock	4,976			909
Treasury Stock Activity	(1		)	—
Debt Issuance and Financing Fees	—			131
Net Cash Used in Financing Activities in Continuing Operations	(13,954		)	(33,408		)
Net Cash Used in Financing Activities in Discontinued Operations	—			(150		)
Net Cash Used in Financing Activities	(13,954		)	(33,558		)
Net (Decrease) Increase in Cash and Cash Equivalents	(13,333		)	3,181
Cash and Cash Equivalents at Beginning of Period	327,420			21,861
Cash and Cash Equivalents at End of Period	$	314,087		$	25,042

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

The balance sheet at December 31, 2013 has been derived from the Audited Consolidated Financial Statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2013 included in CONSOL Energy Inc.'s Form 10-K.

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

Basic earnings per share are computed by dividing net income (loss) attributable to shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, performance stock options, and CONSOL stock units, and the assumed vesting of restricted and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options, performance share options, and CONSOL stock units were exercised, that outstanding restricted stock units and performance share 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,
	2014	2013
Anti-Dilutive Options	359,488	5,011,771
Anti-Dilutive Restricted Stock Units	—	1,459,228
Anti-Dilutive Performance Share Units	—	700,040
Anti-Dilutive Performance Share Options	—	602,101
Anti-Dilutive CONSOL Stock Units	—	891,921
	359,488	8,665,061

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



	Three Months Ended March 31,
	2014	2013
Options	265,339	84,994
Restricted Stock Units	334,399	478,509
Performance Share Units	378,971	159,228
	978,709	722,731

The weighted average exercise price per share of the options exercised during the three months ended March 31, 2014 and 2013 was $18.74 and $10.65, respectively.

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



	Three Months Ended March 31,
	2014			2013
Income (Loss) from Continuing Operations	$	121,690		$	(3,724	)
(Loss) Income from Discontinuing Operations	(5,687		)	1,903
Less: Net Income Attributable to Noncontrolling Interest	—			257
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	116,003		$	(1,564	)
Weighted average shares of common stock outstanding:
Basic	229,526,033			228,318,123
Effect of stock-based compensation awards	1,341,493			—
Dilutive	230,867,526			228,318,123
Earnings per share:
Basic (Continuing Operations)	$	0.53		$	(0.02	)
Basic (Discontinuing Operations)	(0.02		)	0.01
Total Basic	$	0.51		$	(0.01	)

Dilutive (Continuing Operations)	$	0.53		$	(0.02	)
Dilutive (Discontinuing Operations)	(0.03		)	0.01
Total Dilutive	$	0.50		$	(0.01	)

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



	Gains and Losses on Cash Flow Hedges			Postretirement Benefits			Total
Balance at December 31, 2013	$	42,493		$	(367,610	)	$	(325,117	)
Other comprehensive income before reclassifications	(46,965		)	—			(46,965		)
Amounts reclassified from accumulated other comprehensive income	16,313			5,119			21,432
Current period other comprehensive income	(30,652		)	5,119			(25,533		)
Balance at March 31, 2014	$	11,841		$	(362,491	)	$	(350,650	)

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



	Three Months Ended March 31,
	2014			2013
Derivative Instruments (Note 12)
Natural gas price swaps and options	$	27,264		$	(36,679	)
Tax (expense) benefit	(10,951		)	13,966
Net of tax	$	16,313		$	(22,713	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(2,542	)	$	(8,212	)
Recognized net actuarial loss	10,646			25,188
Settlement loss	—			27,115
Total	8,104			44,091
Tax expense	(2,985		)	(16,831		)
Net of tax	$	5,119		$	27,260

*Excludes $18,497, net of tax, related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the three months ended March 31, 2013.

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

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

In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which includes all five of its longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). CONSOL Energy retained overriding royalty interests in certain reserves sold in the agreement. Murray Energy also assumed $2,050,656 of CONSOL Energy's employee benefit obligations valued as of December 5, 2013 and its UMWA 1974 Pension Trust obligations. Murray Energy is primarily liable for all 1993 Coal Act liabilities. Cash proceeds of $825,285 were received related to this transaction, which were net of $24,715 in transaction fees. Proceeds are subject to adjustments related to working capital. A pre-tax gain of $1,035,346 was included in Income from Discontinued Operations on the Consolidated Statement of Income. In the first quarter of 2014, there was a pre-tax reduction in gain on sale of $7,044 related to the estimated working capital adjustment and various other miscellaneous items. Final settlement of working capital adjustments are currently being evaluated and are not expected to be material.

For all periods presented in the accompanying Consolidated Statements of Income, the sale of CCC was classified as discontinued operations. There were no other active businesses classified as discontinued operations in the presented periods.

In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unit of Dominion Resources. The acreage, which is associated with Dominion’s Fink-Kennedy, Lost Creek, and Racket Newberne gas storage fields in West Virginia, lies in the northern portion of Lewis County and the southern portion of Harrison County. CONSOL Energy anticipates that over one-half of the acres will have wet gas. CONSOL Energy has acquired the gas rights to both the Marcellus Shale and the Upper Devonian formations in the storage fields. Consideration of up to $190,000 will be paid by CONSOL Energy in two installments: 50% was paid at closing and the balance is due over time as the acres are drilled. In addition, CONSOL Energy will pay an overriding royalty to Dominion Resources based on a sliding scale. 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, our joint venture partner, acquired 50% of the acres and will reimburse CONSOL Energy for 50% of the associated costs.

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

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

NOTE 3—COMPONENTS OF PENSION AND OTHER POST-EMPLOYMENT BENEFIT (OPEB) PLANS NET PERIODIC BENEFIT COSTS:

Components of net periodic costs (benefits) for the three months ended March 31 are as follows:



	Pension Benefits						Other Post-Employment Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	4,308		$	5,706		$	2,331		$	4,849
Interest cost	9,151			8,843			12,097			29,619
Expected return on plan assets	(12,747		)	(12,144		)	—			—
Amortization of prior service credits	(346		)	(408		)	(2,196		)	(7,804		)
Recognized net actuarial loss	5,891			12,175			6,369			17,595
Settlement loss	—			27,115			—			—
Net periodic benefit cost	$	6,257		$	41,287		$	18,601		$	44,259

Expenses attributable to discontinued operations included in net periodic cost above were $2,862 and $25,394 for the three months ended March 31, 2013 for the Pension Plans and the Other Post-Employment Benefit Plan, respectively.

For the three months ended March 31, 2014, $6,197 was paid to the pension trust from operating cash flows. Currently, depending upon asset values and asset returns held in the trust, we expect to contribute $24,000 to the pension trust in 2014. Net periodic benefit costs are allocated to Exploration and Production Costs - Direct Administrative and Selling Expenses and Coal Costs - Operating and Other Costs in the Consolidated Statements of Income.

According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the three months ended March 31, 2013. Accordingly, CONSOL Energy recognized expense of $27,115 for the three months ended March 31, 2013 in Other Costs - Miscellaneous Operating Expense in the Consolidated Statements of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in the projected benefit obligation due to the lump sum payments. The settlement charges noted above also resulted in a remeasurement of the pension plan at March 31, 2013. The March 31, 2013 remeasurement resulted in a change to the discount rate to 4.12% at March 31, 2013 from 4.00% at December 31, 2012. The remeasurement reduced the pension liability by $29,916. The settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $35,261 in Other Comprehensive Income, net of $21,770 in deferred taxes. It is reasonably possible that CONSOL Energy will incur settlement charges in 2014, which would require the pension plan to be remeasured using updated assumptions.

CONSOL Energy does not expect to contribute to the other post-employment benefit plan in 2014. We intend to pay benefit claims as they become due. For the three months ended March 31, 2014, $14,842 of other post-employment benefits have been paid.

NOTE 4—COMPONENTS OF COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION NET PERIODIC BENEFIT COSTS:

Components of net periodic costs (benefits) for the three months ended March 31, are as follows:



	CWP						Workers' Compensation
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Service cost	$	1,419		$	2,135		$	2,445		$	3,533
Interest cost	1,384			1,808			894			1,655
Amortization of actuarial gain	(1,549		)	(4,213		)	(95		)	(699		)
State administrative fees and insurance bond premiums	—			—			1,111			1,659
Legal and administrative costs	—			—			—			591
Net periodic cost (benefit)	$	1,254		$	(270	)	$	4,355		$	6,739

Expenses (income) attributable to discontinued operations included in the net periodic cost (benefit) above were $(164) and $2,535 for the three months ended March 31, 2013 for CWP and Workers' Compensation, respectively.

CONSOL Energy does not expect to contribute to the CWP plan in 2014. We intend to pay benefit claims as they become due. For the three months ended March 31, 2014, $3,210 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2014. We intend to pay benefit claims as they become due. For the three months ended March 31, 2014, $4,627 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

The effective tax rate for the three months ended March 31, 2014 and 2013 was 6.5% and 19.3%, respectively.

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, a $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.

For the three months ended March 31, 2014, CONSOL Energy recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. The tax benefit of $8,351 related to increased percentage depletion deductions offset by $585 of tax expense related to changes in the Domestic Production Activities Deduction and various other estimates.

The effective rate for the three months ended March 31, 2013 differs from the U.S. federal statutory rate of 35% primarily due to a $1,343 income tax charge for the effect of excess percentage depletion on annual profitability.

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

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of March 31, 2014 and 2013, the Company reported an accrued interest liability relating to uncertain tax positions of $1,351 and $5,165, respectively. The accrued interest liability includes $4,849 of interest income and $335 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the three months ended March 31, 2014 and 2013, respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of March 31, 2014 and 2013, CONSOL Energy had no accrued liability for tax penalties.

CONSOL Energy and its subsidiaries file federal income tax returns with the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local, or non-U.S. income tax examinations by tax authorities for the years before 2010. The Internal Revenue Service has issued its audit report related to the examination of CONSOL Energy’s 2008 and 2009 U.S. income tax returns during the three months ended March 31, 2014. As a result of these findings, CONSOL Energy paid federal income tax deficiencies of $4,464 and $1,001, respectively. The deficiencies were the result of changes in the timing of certain tax deductions. The changes in timing of these tax deductions increased the tax benefit of percentage depletion by $2,925 and $4,493 in tax years 2008 and 2009, respectively. The Company also recognized additional tax benefits of $1,402 primarily related to an increase in the Domestic Production Activities Deduction for the audited periods.

NOTE 6—INVENTORIES:

Inventory components consist of the following:



	March 31, 2014		December 31, 2013
Coal	$	32,099	$	31,944
Merchandise for resale	36,069		38,263
Supplies	88,017		87,707
Total Inventories	$	156,185	$	157,914

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

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $19,424 and $18,836 at March 31, 2014 and December 31, 2013, respectively.

NOTE 7—ACCOUNTS RECEIVABLE SECURITIZATION:

CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $125,000. The facility also allows for the issuance of letters of credit against the $125,000 capacity which was reduced from $200,000 on March 28, 2014. At March 31, 2014, there were letters of credit outstanding against the facility of $61,930. CONSOL Energy management believes that these letters of credit will expire without being funded, and therefore the commitments will not have a material adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements.

CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation, 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, our collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

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

The cost of funds under this facility is based upon commercial paper rates or LIBOR, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $279 and $472 for the three months ended March 31, 2014 and 2013, respectively. These costs have been recorded as financing fees which are included in

in the Miscellaneous Operating Expense in the Other Cost line in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2015.

At March 31, 2014 and December 31, 2013, eligible accounts receivable totaled $98,500 and $115,000, respectively. There was $36,570 subordinated retained interest at March 31, 2014 and $48,945 subordinated retained interest at December 31, 2013. There were no borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of March 31, 2014 and no borrowings at December 31, 2013. The accounts receivable securitization program had no change in the three months ended March 31, 2014 and decreased by $7,727 in the three months ended March 31, 2013. The decrease is reflected in the Net Cash Used in Financing Activities in the Consolidated Statement of Cash Flows. In accordance with the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

NOTE 8—PROPERTY, PLANT AND EQUIPMENT:



	March 31, 2014		December 31, 2013
Coal and other plant and equipment	$	3,695,573	$	3,681,051
Intangible drilling cost	2,044,717		1,937,336
Proven gas properties	1,673,555		1,670,404
Unproven gas properties	1,483,016		1,463,406
Coal properties and surface lands	1,404,043		1,409,408
Gas gathering equipment	1,082,873		1,058,008
Gas wells and related equipment	718,653		688,548
Airshafts	414,181		397,466
Mine development	411,432		354,607
Leased coal lands	388,033		388,020
Coal advance mining royalties	385,197		381,348
Other gas assets	127,019		126,239
Gas advance royalties	22,326		22,668
Total Property Plant and Equipment	13,850,618		13,578,509
Less: Accumulated DD&A	4,245,627		4,136,247
Total Net PP&E	$	9,604,991	$	9,442,262

Industry Participation Agreements

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

CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 109 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess is obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. As of March 31, 2014, Hess’ remaining carry obligation is $208,127.

CNX Gas Company is party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 437 thousand net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owns a 50% undivided interest. Under the agreement, as amended, Noble Energy is obligated to pay a total of approximately $1,884,000 in the form of a one-third drilling carry of certain of CONSOL Energy’s working interest obligations as the property is developed, subject to certain limitations. These limitations include the suspension of the carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. Due to the increase in average natural gas prices, the carry is in effect beginning March 1, 2014, and will remain effective until average natural gas prices are below $4.00/MMbtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble Energy's carried cost obligation. As of March 31, 2014, Noble Energy’s remaining carry obligation is $1,859,978.

NOTE 9—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's $1,000,000 Senior Secured Credit Agreement, as amended, expires April 12, 2016. The amendment reduced the availability from $1,500,000 to $1,000,000 resulting in an acceleration of previously deferred financing charges of $3,195 during the year ended December 31, 2013. 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 $1,000,000 of borrowings and letters of credit. CONSOL Energy can request an additional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (Adjusted EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. The interest coverage ratio was 2.52 to 1.00 at March 31, 2014. The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio was 0.00 to 1.00 at March 31, 2014. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. At March 31, 2014, the $1,000,000 facility had no borrowings outstanding and $167,941 of letters of credit outstanding, leaving $832,059 of unused capacity. At December 31, 2013, the $1,000,000 facility had no borrowings outstanding and $206,988 of letters of credit outstanding, leaving $793,012 of unused capacity.

CNX Gas Corporation's (CNX Gas) $1,000,000 Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 for borrowings and letters of credit. CNX Gas can request an additional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, pay dividends and merge with another corporation. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE Gathering, LLC (CONE) are unrestricted. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.42 to 1.00 at March 31, 2014. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 35.48 to 1.00 at March 31, 2014. At March 31, 2014, the $1,000,000 facility had no borrowings outstanding and $94,703 of letters of credit outstanding, leaving $905,297 of unused capacity. At December 31, 2013, the $1,000,000 facility had no borrowings outstanding and $87,643 of letters of credit outstanding, leaving $912,357 of unused capacity.

NOTE 10—LONG-TERM DEBT:



	March 31, 2014		December 31, 2013
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	1,500,000
Senior notes due April 2020 at 8.25%, issued at par value	1,250,000		1,250,000
Senior notes due March 2021 at 6.375%, issued at par value	250,000		250,000
MEDCO revenue bonds in series due September 2025 at 5.75%	102,865		102,865
Advance royalty commitments (7.93% weighted average interest rate for March 31, 2014 and December 31, 2013)	11,182		11,182
Other long-term notes maturing at various dates through 2031 (total value of $5,580 and $5,923 less unamortized discount of $940 and $1,050 at March 31, 2014 and December 31, 2013, respectively).	4,640		4,873
	3,118,687		3,118,920
Less amounts due in one year *	3,512		2,957
Long-Term Debt	$	3,115,175	$	3,115,963

* Excludes current portion of Capital Lease Obligations of $8,546 and $8,498 at March 31, 2014 and December 31, 2013, respectively.

Accrued interest related to Long-Term Debt of $113,593 and $63,272 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at March 31, 2014 and December 31, 2013, respectively.

NOTE 11—COMMITMENTS AND CONTINGENT LIABILITIES:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amounts cannot be reasonably estimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimated, exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $390,121.

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

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on over 15 years of experience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets. Past payments by Fairmont with respect to asbestos cases have not been material.

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

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styled Addison v. CNX Gas Company, et al. The lawsuit alleges that the plaintiff class consists of gas lessors

whose gas ownership is in conflict. The lawsuit alleges that the Virginia Supreme Court and General Assembly have decided that the plaintiff owns the gas and is entitled to royalties held in escrow by the Commonwealth of Virginia or CNX Gas Company. The lawsuit also alleges CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breach of fiduciary duties; and unjust enrichment. The District Judge granted, in part, CNX Gas Company’s Motion to Dismiss. An Amended Complaint was filed which added an additional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and was denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for Class Certification. On September 30, 2013, the District Judge entered an Order overruling CNX Gas Company’s Objections, adopting the Report & Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed a Petition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a ruling on the Petition but assigning the case to a merits panel. Now fully briefed, the Fourth Circuit has scheduled oral argument for May 13, 2014. Plaintiffs have filed Motions for Summary Judgment on the issue of ownership of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge heard argument on the summary judgment motions on January 6, 2014. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheets.

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

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

Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas Company. The complaint, as amended, seeks injunctive relief, including removing CNX Gas Company from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court. The suit further sought a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled in favor of CNX Gas Company and CONSOL Energy. On March 3, 2014, the Company won summary judgment on Counts 1 through 10 of the Amended Complaint, each relating to the alleged trespass of horizontal CBM wells into strata other than the Pittsburgh 8 Seam. The Court rejected each of those claims, essentially holding that if CNX Gas Company went out of the coal seam, it had no intention to do so and, in any event, the plaintiff could not prove any damages as a result. The last remaining Count, seeking to quiet title to approximately 40 acres of Pittsburgh Seam coal, was nonsuited by Plaintiffs, without prejudice, on March 26, 2014. On March 28, 2014, Plaintiffs filed Notices of Appeal with the Pennsylvania Superior Court on all issues decided in CONSOL Energy’s favor.

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

At March 31, 2014, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.



	Amount of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	151,311	$	87,507	$	63,804	$	—	$	—
Environmental	56,293		34,346		21,947		—		—
Other	117,041		80,095		36,946		—		—
Total Letters of Credit	324,645		201,948		122,697		—		—
Surety Bonds:
Employee-Related	204,884		198,504		6,380		—		—
Environmental	653,395		643,531		9,864		—		—
Other	22,893		22,887		5		—		1
Total Surety Bonds	881,172		864,922		16,249		—		1
Guarantees:
Coal	283,360		175,350		108,010		—		—
Other	69,120		35,611		10,658		12,090		10,761
Total Guarantees	352,480		210,961		118,668		12,090		10,761
Total Commitments	$	1,558,297	$	1,277,831	$	257,614	$	12,090	$	10,762

Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company (CCC) and certain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray Energy 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, 2014, the fair value of these guarantees was $3,000 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 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, 2014, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	181,821
1 - 3 years	330,612
3 - 5 years	260,249
More than 5 years	787,443
Total Purchase Obligations	$	1,560,125

Costs related to these purchase obligations include:



	Three Months Ended
	March 31,
	2014		2013
Major equipment purchases	$	77,635	$	3,092
Firm transportation expense	36,930		28,525
Gas drilling obligations	24,164		28,863
Total costs related to purchase obligations	$	138,729	$	60,480

NOTE 12—DERIVATIVE INSTRUMENTS:

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

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

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

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

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

CONSOL Energy has entered into swap and option contracts for natural gas to manage the price risk associated with the forecasted natural gas sales. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted sales from the underlying commodity. As of March 31, 2014, the total notional amount of the Company’s outstanding derivative instruments was 276.2 billion cubic feet. These derivative instruments are forecasted to settle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shown on the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/or Changes in Other Liabilities. Assuming no changes in price during the next twelve months, $1,633 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Natural Gas, NGL's and Oil Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at March 31, 2014 of CONSOL Energy's derivative instruments, which all qualify as cash flow hedges, was an asset of $58,947 and a liability of $43,700. The total asset is comprised of $37,152 and $21,795 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $38,679 and $5,021 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

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

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



	For the Three Months Ended March 31,
	2014			2013
Natural Gas Price Swaps and Options
Beginning Balance – Accumulated OCI	$	42,493		$	76,761
Gain/(Loss) recognized in Accumulated OCI	$	(46,965	)	$	(18,595	)
Less: Gain/(Loss) reclassified from Accumulated OCI into Natural Gas, NGL's and Oil Sales	$	(16,313	)	$	22,713
Ending Balance – Accumulated OCI	$	11,841		$	35,453
Gain/(Loss) recognized in Natural Gas, NGL's and Oil Sales for ineffectiveness	$	355		$	1,041

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

NOTE 13—FAIR VALUE OF FINANCIAL INSTRUMENTS:

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



	Fair Value Measurements at March 31, 2014						Fair Value Measurements at December 31, 2013
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	15,247	$	—	$	—	$	65,449	$	—

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

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

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

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



	March 31, 2014						December 31, 2013
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	314,087		$	314,087		$	327,420		$	327,420
Long-Term Debt	$	(3,118,687	)	$	(3,314,396	)	$	(3,118,920	)	$	(3,299,875	)

NOTE 14—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Exploration and Production (E&P) and Coal. The principal activity of the E&P division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The E&P division includes four reportable segments. These reportable segments are Marcellus, Coalbed Methane, Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as various other activities assigned to the E&P division but not allocated to each individual well type. The principal activities of the Coal division are mining, preparation and marketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the three months ended March 31, 2014, the Thermal aggregated segment includes the following mines: Bailey Complex, Enlow Fork, and Miller Creek Complex. For the three months ended March 31, 2014, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the three months ended March 31, 2014, the High Volatile Metallurgical aggregated segment includes: Bailey Complex and Enlow Fork coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to each individual mine. CONSOL Energy’s All Other segment includes industrial supplies, coal terminal operations and various other corporate activities that are not allocated to the E&P or coal segment. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (E&P, coal, and other) and are not allocated between each individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are not allocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than one segment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.

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



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P		Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	124,957	$	96,071	$	32,345		$	12,925		$	266,298	$	416,969	$	84,541	$	28,932	$	4,239		$	534,681	$	69,287	$	—		$	870,266	(A)
Sales—purchased gas	—		—		—			3,574			3,574		—		—		—		—			—		—		—			3,574
Sales—gas royalty interests	—		—		—			26,645			26,645		—		—		—		—			—		—		—			26,645
Freight—outside	—		—		—			—			—		—		—		—		9,945			9,945		—		—			9,945
Intersegment transfers	—		—		—			897			897		—		—		—		—			—		19,312		(20,209		)	—
Total Sales and Freight	$	124,957	$	96,071	$	32,345		$	44,041		$	297,414	$	416,969	$	84,541	$	28,932	$	14,184		$	544,626	$	88,599	$	(20,209	)	$	910,430
Earnings (Loss) Before Income Taxes	$	59,105	$	33,619	$	(1,757	)	$	(11,223	)	$	79,744	$	148,568	$	11,430	$	9,104	$	(61,937	)	$	107,165	$	1,497	$	(58,227	)	$	130,179	(B)
Segment assets											$	6,521,994										$	4,168,372	$	291,767	$	602,342		$	11,584,475	(C)
Depreciation, depletion and amortization											$	71,729										$	56,063	$	1,324	$	—		$	129,116
Capital expenditures											$	265,970										$	184,508	$	531	$	—		$	451,009

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

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

(C) Includes investments in unconsolidated equity affiliates of $223,875, $23,923 and $61,327 for E&P, Coal and All Other, respectively.

Industry segment results for the three months ended March 31, 2013 are:



	Marcellus Shale		Coalbed Methane		Shallow Oil and Gas			Other Gas			Total E&P			Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	48,411	$	83,640	$	32,436		$	3,355		$	167,842		$	345,940	$	146,828	$	49,478	$	5,663		$	547,909	$	68,684	$	—		$	784,435		(D)
Sales—purchased gas	—		—		—			1,358			1,358			—		—		—		—			—		—		—			1,358
Sales—gas royalty interests	—		—		—			14,204			14,204			—		—		—		—			—		—		—			14,204
Freight—outside	—		—		—			—			—			—		—		—		12,253			12,253		—		—			12,253
Intersegment transfers	—		—		—			836			836			—		—		—		—			—		35,478		(36,314		)	—
Total Sales and Freight	$	48,411	$	83,640	$	32,436		$	19,753		$	184,240		$	345,940	$	146,828	$	49,478	$	17,916		$	560,162	$	104,162	$	(36,314	)	$	812,250
Earnings (Loss) Before Income Taxes	$	13,768	$	21,180	$	(4,037	)	$	(31,554	)	$	(643	)	$	93,459	$	54,717	$	10,737	$	(59,256	)	$	99,657	$	2,575	$	(106,205	)	$	(4,616	)	(E)
Segment assets											$	5,879,988											$	4,058,992	$	358,663	$	2,295,551		$	12,593,194		(F)
Depreciation, depletion and amortization											$	52,988											$	57,190	$	1,400	$	—		$	111,578
Capital expenditures											$	207,129											$	141,251	$	1,437	$	—		$	349,817


(D)	Included in the Coal segment are sales of $157,604 to Xcoal Energy & Resources, which comprises over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $3,181, $1,532 and $84 for E&P, Coal and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $167,058, $22,635 and $58,434 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,
	2014			2013
Segment Earnings Before Income Taxes for total reportable business segments	$	186,909		$	99,014
Segment Earnings Before Income Taxes for all other businesses	1,497			2,575
Interest expense, net and other non-operating activity (G)	(53,943		)	(52,660		)
Other Corporate Items (G)	(4,284		)	(53,545		)
Earnings Before Income Taxes	$	130,179		$	(4,616	)



Total Assets:	March 31,
Total Assets:	2014		2013
Segment assets for total reportable business segments	$	10,690,366	$	9,938,980
Segment assets for all other businesses	291,767		358,663
Items excluded from segment assets:
Cash and other investments (G)	300,090		23,652
Recoverable income taxes	4,434		6,602
Deferred tax assets	265,226		99,785
Bond issuance costs	32,592		39,939
Discontinued Operations	—		2,125,573
Total Consolidated Assets	$	11,584,475	$	12,593,194

_________________________

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

NOTE 15—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:

The payment obligations under the $1,500,000, 8.000% per annum senior notes due April 1, 2017, the $1,250,000, 8.250% per annum senior notes due April 1, 2020, and the $250,000, 6.375% per annum senior notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other wholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the Three Months Ended 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	173,103			27,720		54,778		22,271			(222,818		)	55,054
Gain (Loss) on Sale of Assets	—			3,152		514		3			—			3,669
Total Revenue and Other Income	173,103			328,285		610,401		81,078			(223,714		)	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	—			2,662		—		31			406			3,099
Production Royalty Interests and Purchased Gas Costs	—			26,108		—		—			(12		)	26,096
Other Corporate Expenses	—			25,719		—		—			445			26,164
General and Administrative	—			17,809		—		—			(445		)	17,364
Total Exploration and Production Costs	—			248,892		—		31			394			249,317
Coal Costs
Operating and Other Costs	14,291			—		313,454		—			(896		)	326,849
Royalties and Production Taxes	—			—		45,197		—			(18,709		)	26,488
Direct Administrative and Selling	150			—		11,144		—			—			11,294
Depreciation, Depletion and Amortization	—			—		56,063		—			—			56,063
Freight Expense	—			—		9,945		—			—			9,945
General and Administrative Costs	2,434			—		10,079		—			—			12,513
Other Corporate Expenses	19,295			—		—		—			—			19,295
Total Coal Costs	36,170			—		445,882		—			(19,605		)	462,447
Other Costs
Miscellaneous Operating Expense	7,027			—		7,707		78,203			(18,388		)	74,549
General and Administrative Costs	210			—		196		—			—			406
Depreciation, Depletion and Amortization	6			—		845		473			—			1,324
Interest Expense	48,433			1,809		13,222		73			(12,606		)	50,931
Total Other Costs	55,676			1,809		21,970		78,749			(30,994		)	127,210
Total Costs And Expenses	91,846			250,701		467,852		78,780			(50,205		)	838,974
Earnings Before Income Tax	81,257			77,584		142,549		2,298			(173,509		)	130,179
Income Taxes	(34,746		)	30,714		11,651		870			—			8,489
Income From Continuing Operations	116,003			46,870		130,898		1,428			(173,509		)	121,690
Income From Discontinued Operations, net	—			—		—		(5,687		)	—			(5,687		)
Net Income Attributable to CONSOL Energy Shareholders	$	116,003		$	46,870	$	130,898	$	(4,259	)	$	(173,509	)	$	116,003

Balance Sheet at March 31, 2014 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	298,452		$	14,830	$	—		$	805	$	—		$	314,087
Accounts and Notes Receivable:
Trade	—			90,369		—			265,237		—			355,606
Notes Receivable	1,283			—		24,626			—		—			25,909
Other Receivables	11,367			204,786		20,345			3,350		—			239,848
Inventories	—			15,465		104,999			35,721		—			156,185
Deferred Income Taxes	254,138			11,088		—			—		—			265,226
Recoverable Income Taxes	(8,706		)	13,140		—			—		—			4,434
Prepaid Expenses	31,386			42,059		22,290			1,806		—			97,541
Total Current Assets	587,920			391,737		172,260			306,919		—			1,458,836
Property, Plant and Equipment:
Property, Plant and Equipment	156,226			7,162,125		6,506,116			26,151		—			13,850,618
Less-Accumulated Depreciation, Depletion and Amortization	140,487			1,259,469		2,826,369			19,302		—			4,245,627
Total Property, Plant and Equipment-Net	15,739			5,902,656		3,679,747			6,849		—			9,604,991
Other Assets:
Investment in Affiliates	12,105,348			223,874		107,608			—		(12,127,705		)	309,125
Notes Receivable	95			—		—			—		—			95
Other	136,391			27,947		38,185			8,905		—			211,428
Total Other Assets	12,241,834			251,821		145,793			8,905		(12,127,705		)	520,648
Total Assets	$	12,845,493		$	6,546,214	$	3,997,800		$	322,673	$	(12,127,705	)	$	11,584,475
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	117,351		$	354,262	$	20,137		$	14,834	$	—		$	506,584
Accounts Payable (Recoverable)—Related Parties	4,549,533			78,880		(5,112,248		)	131,948		351,887			—
Current Portion Long-Term Debt	1,523			6,434		3,322			779		—			12,058
Short-Term Notes Payable	—			351,887		—			—		(351,887		)	—
Other Accrued Liabilities	167,178			139,320		322,471			8,336		—			637,305
Current Liabilities of Discontinued Operations	—			—		—			14,400		—			14,400
Total Current Liabilities	4,835,585			930,783		(4,766,318		)	170,297		—			1,170,347
Long-Term Debt:	3,004,520			41,727		113,164			1,930		—			3,161,341
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(187,476		)	491,880		—			—		—			304,404
Postretirement Benefits Other Than Pensions	—			—		960,197			—		—			960,197
Pneumoconiosis Benefits	—			—		111,566			—		—			111,566
Mine Closing	—			—		320,270			—		—			320,270
Gas Well Closing	—			121,081		56,495			—		—			177,576
Workers’ Compensation	—			—		71,022			336		—			71,358
Salary Retirement	42,506			—		—			—		—			42,506
Reclamation	—			—		39,587			—		—			39,587
Other	58,071			65,718		9,247			—		—			133,036
Total Deferred Credits and Other Liabilities	(86,899		)	678,679		1,568,384			336		—			2,160,500
Total CONSOL Energy Inc. Stockholders’ Equity	5,092,287			4,895,025		7,082,570			150,110		(12,127,705		)	5,092,287
Total Liabilities and Equity	$	12,845,493		$	6,546,214	$	3,997,800		$	322,673	$	(12,127,705	)	$	11,584,475

Income Statement for the Three Months Ended March 31, 2013 (unaudited):



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Revenues and Other Income:
Natural Gas, NGLs and Oil Sales	$	—		$	168,679		$	—	$	—	$	(837	)	$	167,842
Coal Sales	—			—			547,909		—		—			547,909
Other Outside Sales	—			—			14,631		54,053		—			68,684
Gas Royalty Interests and Purchased Gas Sales	—			15,562			—		—		—			15,562
Freight-Outside Coal	—			—			12,253		—		—			12,253
Miscellaneous Other Income	77,976			12,768			39,531		5,370		(107,258		)	28,387
Gain (Loss) on Sale of Assets	—			456			1,847		3		—			2,306
Total Revenue and Other Income	77,976			197,465			616,171		59,426		(108,095		)	842,943
Costs and Expenses:
Exploration and Production Costs
Lease Operating Expense	—			22,014			—		—		—			22,014
Transportation, Gathering and Compression	—			48,433			—		—		—			48,433
Production, Ad Valorem, and Other Fees	—			4,569			—		—		—			4,569
Direct Administrative and Selling	—			11,086			—		—		—			11,086
Depreciation, Depletion and Amortization	—			52,988			—		—		—			52,988
Exploration and Production Related Other Costs	—			10,488			—		1,284		(1,283		)	10,489
Production Royalty Interests and Purchased Gas Costs	—			12,776			—		—		(11		)	12,765
Other Corporate Expenses	—			24,458			—		—		935			25,393
General and Administrative	—			9,525			—		—		(935		)	8,590
Total Exploration and Production Costs	—			196,337			—		1,284		(1,294		)	196,327
Coal Costs
Operating and Other Costs	10,066			—			325,333		—		(384		)	335,015
Royalties and Production Taxes	—			—			29,276		—		(837		)	28,439
Direct Administrative and Selling	—			—			10,884		—		—			10,884
Depreciation, Depletion and Amortization	—			—			57,190		—		—			57,190
Freight Expense	—			—			12,253		—		—			12,253
General and Administrative Costs	—			—			10,763		36		(1,498		)	9,301
Other Corporate Expenses	18,417			—			—		—		1,498			19,915
Total Coal Costs	28,483			—			445,699		36		(1,221		)	472,997
Other Costs
Miscellaneous Operating Expense	38,085			—			32,324		53,995		(1,369		)	123,035
General and Administrative Costs	232			—			159		32		—			423
Depreciation, Depletion and Amortization	6			—			910		484		—			1,400
Interest Expense	50,169			1,661			1,643		11		(107		)	53,377
Total Other Costs	88,492			1,661			35,036		54,522		(1,476		)	178,235
Total Costs And Expenses	116,975			197,998			480,735		55,842		(3,991		)	847,559
Earnings Before Income Tax	(38,999		)	(533		)	135,436		3,584		(104,104		)	(4,616		)
Income Taxes	(37,435		)	(208		)	35,395		1,356		—			(892		)
Income From Continuing Operations	(1,564		)	(325		)	100,041		2,228		(104,104		)	(3,724		)
Income From Discontinued Operations, net	—			—			—		1,903		—			1,903
Net Income	(1,564		)	(325		)	100,041		4,131		(104,104		)	(1,821		)
Less: Net Income Attributable to Noncontrolling Interests	—			257			—		—		—			257
Net Income Attributable to CONSOL Energy Shareholders	$	(1,564	)	$	(68	)	$	100,041	$	4,131	$	(104,104	)	$	(1,564	)

Balance Sheet at December 31, 2013:



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	320,473		$	6,238		$	—		$	709	$	—		$	327,420
Accounts and Notes Receivable:
Trade	—			71,911			—			260,663		—			332,574
Notes Receivable	1,238			—			24,623			—		—			25,861
Other Receivables	17,657			207,128			14,969			4,219		—			243,973
Inventories	—			15,185			99,320			43,409		—			157,914
Recoverable Income Taxes	(16,262		)	26,967			—			—		—			10,705
Deferred Income Taxes	219,566			(8,263		)	—			—		—			211,303
Prepaid Expenses	43,698			65,701			24,915			1,528		—			135,842
Total Current Assets	586,370			384,867			163,827			310,528		—			1,445,592
Property, Plant and Equipment:
Property, Plant and Equipment	220,355			6,919,972			6,412,378			25,804		—			13,578,509
Less-Accumulated Depreciation, Depletion and Amortization	145,754			1,188,464			2,783,043			18,986		—			4,136,247
Total Property, Plant and Equipment-Net	74,601			5,731,508			3,629,335			6,818		—			9,442,262
Other Assets:
Investment in Affiliates	11,965,054			206,060			70,222			—		(11,949,661		)	291,675
Notes Receivable	125			—			—			—		—			125
Other	145,401			30,728			28,831			9,053		—			214,013
Total Other Assets	12,110,580			236,788			99,053			9,053		(11,949,661		)	505,813
Total Assets	$	12,771,551		$	6,353,163		$	3,892,215		$	326,399	$	(11,949,661	)	$	11,393,667
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	180,261		$	324,226		$	493		$	9,600	$	—		$	514,580
Accounts Payable (Recoverable)-Related Parties	4,563,327			23,287			(5,055,923		)	136,822		332,487			—
Current Portion of Long-Term Debt	1,029			6,258			3,372			796		—			11,455
Short-Term Notes Payable	—			332,487			—			—		(332,487		)	—
Other Accrued Liabilities	144,612			89,080			322,606			9,399		—			565,697
Current Liabilities of Discontinued Operations	—			—			—			28,239		—			28,239
Total Current Liabilities	4,889,229			775,338			(4,729,452		)	184,856		—			1,119,971
Long-Term Debt:	3,005,458			42,852			113,474			1,775		—			3,163,559
Deferred Credits and Other Liabilities:
Deferred Income Taxes	(232,904		)	475,547			—			—		—			242,643
Postretirement Benefits Other Than Pensions	—			—			961,127			—		—			961,127
Pneumoconiosis Benefits	—			—			111,971			—		—			111,971
Mine Closing	—			—			320,723			—		—			320,723
Gas Well Closing	—			119,429			56,174			—		—			175,603
Workers’ Compensation	—			—			71,136			332		—			71,468
Salary Retirement	48,252			—			—			—		—			48,252
Reclamation	—			—			40,706			—		—			40,706
Other	55,227			61,190			14,938			—		—			131,355
Total Deferred Credits and Other Liabilities	(129,425		)	656,166			1,576,775			332		—			2,103,848
Total CONSOL Energy Inc. Stockholders’ Equity	5,006,289			4,878,807			6,931,418			139,436		(11,949,661		)	5,006,289
Total Liabilities and Equity	$	12,771,551		$	6,353,163		$	3,892,215		$	326,399	$	(11,949,661	)	$	11,393,667

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		)
Net Cash Used in Discontinued Investing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Investing Activities	$	(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		)
Net Cash Used in Discontinued Financing Activities	—			—			—			—			—			—
Net Cash (Used in) Provided by Financing Activities	$	(9,779	)	$	17,944		$	(2,491	)	$	(228	)	$	(19,400	)	$	(13,954	)

Cash Flow for the Three Months Ended March 31, 2013 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by (Used in) Continuing Operations	$	59,082		$	190,004		$	19,298		$	(54,706	)	$	—	$	213,678
Net Cash Provided by Discontinued Operating Activities	—			—			—			54,603			—		54,603
Net Cash Provided by (Used in) Operating Activities	$	59,082		$	190,004		$	19,298		$	(103	)	$	—	$	268,281
Cash Flows from Investing Activities:
Capital Expenditures	$	(1,504	)	$	(207,129	)	$	(141,184	)	$	—		$	—	$	(349,817	)
Change in Restricted Cash	—			—			48,294			—			—		48,294
Proceeds From Sales of Assets	(75		)	343			74,352			3			—		74,623
(Investments in), net of Distributions from, Equity Affiliates	—			(12,000		)	(500		)	—			—		(12,500		)
Net Cash (Used in) Provided by Continuing Operations	(1,579		)	(218,786		)	(19,038		)	3			—		(239,400		)
Net Cash Provided by Discontinued Investing Activities	—			—			—			7,858			—		7,858
Net Cash (Used in) Provided by Investing Activities	$	(1,579	)	$	(218,786	)	$	(19,038	)	$	7,861		$	—	$	(231,542	)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings	$	(25,612	)	$	—		$	(1,663	)	$	(176	)	$	—	$	(27,451	)
Payments on Short-Term Borrowings	(29,000		)	29,000			—			—			—		—
Payments on Securitization Facility	—			—			—			(7,727		)	—		(7,727		)
Tax Benefit from Stock-Based Compensation	730			—			—			—			—		730
Proceeds from Issuance of Common Stock	909			—			—			—			—		909
Debt Issuance and Financing Fees	131			—			—			—			—		131
Other Financing Activities	—			(1,400		)	1,400			—			—		—
Net Cash (Used in) Provided by Continuing Operations	(52,842		)	27,600			(263		)	(7,903		)	—		(33,408		)
Net Cash Used in Discontinued Financing Activities	—			—			—			(150		)	—		(150		)
Net Cash (Used in) Provided by Financing Activities	$	(52,842	)	$	27,600		$	(263	)	$	(8,053	)	$	—	$	(33,558	)

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		$	130,898	$	(4,259	)	$	(173,509	)	$	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) Attributable to CONSOL Energy Inc. Shareholders	$	90,470		$	16,218		$	136,017	$	(4,259	)	$	(147,976	)	$	90,470

Statement of Comprehensive Income for the Three Months Ended March 31, 2013 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(1,564	)	$	(325	)	$	100,041	$	4,131	$	(104,104	)	$	(1,821	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	45,757			—			45,757		—		(45,757		)	45,757
Net (Decrease) Increase in the Value of Cash Flow Hedge	(18,595		)	(18,595		)	—		—		18,595			(18,595		)
Reclassification of Cash Flow Hedge from OCI to Earnings	(22,713		)	(22,713		)	—		—		22,713			(22,713		)
Other Comprehensive Income (Loss):	4,449			(41,308		)	45,757		—		(4,449		)	4,449
Comprehensive Income (Loss)	2,885			(41,633		)	145,798		4,131		(108,553		)	2,628
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			257			—		—		—			257
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	2,885		$	(41,376	)	$	145,798	$	4,131	$	(108,553	)	$	2,885

NOTE 16—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the three months ended March 31, 2014, CONE Gathering LLC (CONE), a 50% owned affiliate, provided CNX Gas Company LLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $11,672 and $7,327 for the three months ended March 31, 2014 and 2013, respectively, which were included in Exploration and Production Costs - Transportation, Gathering and Compression on the Consolidated Statements of Income.

As of March 31, 2014 and December 31, 2013, CONSOL Energy and CNX Gas Company had a net payable of $5,352 and $5,448, respectively, due to CONE which was comprised of the following items:



	March 31,			December 31,
	2014			2013			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(2,383	)	$	(2,168	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(225		)	(265		)	Accounts Receivable–Other
CONE Gathering Fee Payable	7,960			7,881			Accounts Payable
Net Payable due to CONE	$	5,352		$	5,448

NOTE 17—SUBSEQUENT EVENTS:

On April 16, 2014, CONSOL Energy closed on the private placement of $1,600,000 of 5.875% senior notes due 2022 (the "Notes"). The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy intends to use a portion of the net proceeds of the sale of the Notes to purchase all of the 8.00% senior notes due 2017 (the "2017 Notes") that are validly tendered pursuant to its previously announced tender offer and consent solicitation in respect of the 2017 Notes.CONSOL Energy intends to use the remaining net proceeds from the sale of the Notes to finance the redemption of all of the 2017 Notes that remain outstanding on May 15, 2014, and if any net proceeds remain, to repay other outstanding senior indebtedness.

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


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

General

E&P Marketing and Transportation Update:

First quarter 2014 average dry gas prices, including the impact of our hedging program and net of basis, averaged $5.37 per Mcf. CONSOL Energy's expansion into wet gas production areas provided a liquids value uplift of $0.15/Mcfe, bringing our overall average sales price to $5.52 per Mcfe. Our liquids volumes were 232% higher than in the 2013 first quarter. The continued growth of our wet gas production volumes will increase the uplift on our future average sales prices.

CONSOL Energy continues to develop a diversified portfolio of firm capacity options to support our three-year production growth plan. We benefit by the strategic location of our primary production areas in Southwestern Pennsylvania, Northern West Virginia, and Eastern Ohio. These areas are served by a large concentration of major pipelines that provide us with the capacity to move our production to the major gas markets.

The Company currently has a total of 1.3 Bcf per day of effective firm transportation capacity. This is comprised of 0.8 Bcf per day of firm capacity on existing pipelines, contracted volumes of 0.3 Bcf per day on several pipeline projects that will be completed over the next several years, and an additional 0.2 Bcf per day of long-term firm sales with a major customer that has their own firm capacity. Our firm capacity portfolio will support all of the 2014 production and the majority of our projected volumes for the three-year plan. We are in active negotiations with several pipelines to extend our firm capacity coverage for the longer term. The average cost for the existing and committed firm capacity is approximately $0.23 per MMBtu.

In addition to firm capacity, we have developed a processing portfolio to support the projected volumes from our wet production areas. We have agreements to support the processing of over 115 MMcf per day of gross gas volumes growing to more than 380 MMcf per day in the next twelve months. These commitments are sufficient to cover our processing requirements for the next two years. We will continue to layer in processing capacity to support the liquids development plan.

Coal Marketing Update:

Buchanan Mine shipped 1.1 million tons in the first quarter, of which 489,000 tons were shipped to China. Despite having an excellent cost position, CONSOL Energy has elected to pull Buchanan Mine tons from the Chinese market until some evidence of positive price momentum occurs. The market is finally responding to this low price environment with production cuts, which should lead to supply and demand balance within the next several months. CONSOL Energy has positioned our metallurgical (both low volatile and high volatile) supply at the low end of our recent production range at around 6 million tons, well below the peak levels of 10.5 million tons in 2011 and our 15+ million tons of capacity.

Bailey Mine continues to participate in high volatile markets and shipped 513,000 tons during the first quarter. CONSOL Energy will continue to evaluate the markets and place Bailey Mine tons where they receive the highest return.

The winter of 2013/2014 has resulted in low coal and gas inventories, therefore, CONSOL Energy expects to see further recovery in both coal and gas demand and increased pricing extending through 2014 and into 2015. A thermal NAPP spot market has been re-established with this recent cold winter weather. The combination of low domestic coal and gas inventory levels, weak hydro-electric output, and higher natural gas prices are causing thermal coal buyers to seek higher contract levels to secure a higher coal burn in 2014 and 2015.

CONSOL Energy 2014 - 2016 Guidance

Second quarter gas production, net to CONSOL Energy, is expected to be approximately 50 – 52 Bcfe, while annual 2014 production guidance remains at 215 – 235 Bcfe. CONSOL Energy expects its 2015 and 2016 annual gas production to grow by 30%.

Total hedged natural gas production in the 2014 second quarter is 41.3 Bcf, at an average price of $4.58 per Mcf. CONSOL Energy has begun to implement a dual-track approach to its gas hedging. The Company will continue to use a formulaic approach to a base of hedges, but could layer-in additional opportunistic hedges to capture value from price spikes. CONSOL Energy does not expect to hedge more than 80% of its estimated natural gas production for any given year. The annual gas hedge position for three years is shown in the table below:

GAS DIVISION GUIDANCE



	2014	2015	2016
Total Yearly Production (Bcfe)	215-235	+30%	+30%
Volumes Hedged (Bcf), as of 4/09/14	159.9*	79.4	72.0
Average Hedge Price ($/Mcf)	$4.58	$4.06	$4.16

* Includes 1st Quarter 2014 Actual Settlements of 35.1 Bcf.

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

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

COAL DIVISION GUIDANCE



	Q2 2014		2014		2015
Est. Total Coal Sales	8.1 - 8.5		31 - 33		33.6
Tonnage: Firm	7.9		28.6		12.5
Price: Sold (firm)	$	62.11	$	64.47	$	68.90
Est. Low-Vol Met Sales	0.85 - 0.95		3.6 - 4.2		4.9
Tonnage: Firm	0.5		2.3		0.8
Est. High-Vol Met Sales	0.3		2.0		2.0
Tonnage: Firm	0.3		1.0		0.3
Est. Thermal Sales	7.1 +		26.2+/-		26.7
Tonnage: Firm	7.1		25.3		11.4

Note: While most of the data in the table are single point estimates, the inherent uncertainty of markets and mining operations means that investors should consider a reasonable range around these estimates. CONSOL has chosen not to forecast prices for open tonnage due to ongoing customer negotiations. Firm tonnage is tonnage that is both sold and priced, and excludes collared tons. CONSOL Energy has sold additional coal volumes that are not yet priced. Those volumes are excluded from this table. There are no collared tons in 2014. Collared tons in 2015 are 2.1 million tons, with a ceiling of $64.95 per ton and a floor of $55.99 per ton. Not included in the category breakdowns are the tons from equity affiliates Harrison Resources and Western Allegheny Energy (WAE). Harrison Resources has 0.1 million tons for Q2 2014, and 0.4 million tons for all of 2014 and 2015. WAE has 0.1 million tons for Q2 2014, and 0.5 million tons and 0.6 million tons for all of 2014 and 2015, respectively.

On April 16, 2014, CONSOL Energy closed on the private placement of $1.6 billion of 5.875% senior notes due 2022 (the "Notes"). The Notes are guaranteed by substantially all of CONSOL Energy's wholly-owned domestic restricted subsidiaries. CONSOL Energy intends to use a portion of the net proceeds of the sale of the Notes to purchase all of the 8.00% senior notes due 2017 (the "2017 Notes") that are validly tendered pursuant to its previously announced tender offer and consent solicitation in respect of the 2017 Notes. CONSOL Energy intends to use the remaining net proceeds from the sale of the Notes to finance the redemption of all of the 2017 Notes that remain outstanding on May 15, 2014, and if any net proceeds remain, to repay other outstanding senior indebtedness.

Results of Operations

Three Months Ended March 31, 2014 Compared with Three Months Ended March 31, 2013

Net Income (Loss) Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $116 million, or $0.50 per diluted share, for the three months ended March 31, 2014, compared to a net loss attributable to CONSOL Energy shareholders of $2 million, or $(0.01) per diluted share, for the three months ended March 31, 2013. Included in net income is income from continuing operations of $122 million, or $0.53 per diluted share, for the three months ended March 31, 2014. There was a loss from continuing operations of $4 million, or $(0.02) per diluted share, for the three months ended March 31, 2013. Also included in net income is a loss from discontinued operations of $6 million, or $(0.03) per diluted share, for the three months ended March 31, 2014. Income from discontinued operations was $2 million, or $0.01 per diluted share, for the three months ended March 31, 2013.

The total Exploration and Production (E&P) division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total E&P division contributed income of $80 million before income tax for the three months ended March 31, 2014 compared to a loss of $1 million before income tax for the three months ended March 31, 2013. Total E&P production was 48.4 Bcfe for the three months ended March 31, 2014 compared to 39.2 Bcfe for the three months ended March 31, 2013.

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



	For the Three Months Ended March 31,
in thousands (unless noted)	2014			2013		Variance			Percent Change
LIQUIDS
NGLs:
Sales Volume (MMcfe)	1,569			397		1,172			295.2	%
Sales Volume (Mbbls)	262			66		196			297.0	%
Gross Price ($/Bbl)	$	47.52		$	50.34	$	(2.82	)	(5.6	)%
Gross Revenue	$	12,424		$	3,332	$	9,092		272.9	%

Oil:
Sales Volume (MMcfe)	146			128		18			14.1	%
Sales Volume (Mbbls)	24			21		3			14.3	%
Gross Price ($/Bbl)	$	90.18		$	79.02	$	11.16		14.1	%
Gross Revenue	$	2,192		$	1,683	$	509		30.2	%

Condensate:
Sales Volume (MMcfe)	296			82		214			261.0	%
Sales Volume (Mbbls)	49			14		35			250.0	%
Gross Price ($/Bbl)	$	70.32		$	78.72	$	(8.40	)	(10.7	)%
Gross Revenue	$	3,469		$	1,071	$	2,398		223.9	%

GAS
Sales Volume (MMcf)	46,388			38,621		7,767			20.1	%
Sales Price ($/Mcf)	$	5.71		$	3.59	$	2.12		59.1	%
Hedging Impact ($/Mcf)	$	(0.34	)	$	0.62	$	(0.96	)	(154.8	)%
Gross Revenue including Hedging Impact	$	249,110		$	162,592	$	86,518		53.2	%

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



	For the Three Months Ended March 31,
	2014		2013		Variance		Percent Change
Average Sales Price (per Mcfe)	$	5.52	$	4.30	$	1.22	28.4	%
Average Costs (per Mcfe)	3.63		3.53		0.10		2.8	%
Margin	$	1.89	$	0.77	$	1.12	145.5	%

Total E&P division Natural Gas, NGLs, and Oil sales revenues were $267 million for the three months ended March 31, 2014 compared to $169 million for the three months ended March 31, 2013. The increase was primarily due to the 23.4% increase in total volumes sold, along with a 28.4% increase in average price per Mcfe. The increase in average sales price is the result of an increase in general market prices and the increase in sales of NGLs and condensate. The increase was offset, in part, by various transactions from our hedging program. These financial hedges represented approximately 35.1 Bcf of our produced gas sales volumes for the three months ended March 31, 2014 at an average price of $4.58 per Mcf. These financial hedges represented approximately 16.7 Bcf of our produced gas sales volumes for the three months ended March 31, 2013 at an average price of $4.79 per Mcf.

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


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


•	Ad valorem, severance, and other taxes increased primarily due to the higher average gas sales price and the increase in sales volumes.


•	Lifting costs increased in the period-to-period comparison due to an increase in salt water disposal, well tending, and well site maintenance costs.


•	The increases in unit costs as discussed above were offset, in part, by higher volumes sold.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $107 million of earnings before income tax for the three months ended March 31, 2014 compared to $100 million for the three months ended March 31, 2013. The total coal division sold 8.0 million tons of coal produced from CONSOL Energy mines for the three months ended March 31, 2014 compared to 7.5 million tons for the three months ended March 31, 2013.

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,
	2014		2013		Variance			Percent Change
Average Sales Price per ton sold	$	66.20	$	72.18	$	(5.98	)	(8.3	)%
Average Costs of Goods Sold per ton	45.14		51.13		(5.99		)	(11.7	)%
Margin	$	21.06	$	21.05	$	0.01		—	%

The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets. The coal division priced 2.0 million tons on the export market at an average sales price of $64.42 per ton for the three months ended March 31, 2014 compared to 2.3 million tons at an average price of $75.99 per ton for the three months ended March 31, 2013. All other tons were sold on the domestic market.

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

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

General and Administrative costs are allocated between divisions (E&P, Coal, 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 from continuing operations were made up of the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance			Percent Change
Continuing Operations:
Contributions	$	7	$	1	$	6		600.0	%
Employee wages and related expenses	11		8		3			37.5	%
Advertising and Promotion	2		1		1			100.0	%
Consulting and professional services	6		5		1			20.0	%
Miscellaneous	4		3		1			33.3	%
Continuing Operations General and Administrative Expenses	$	30	$	18	$	12		66.7	%
Discontinued Operations General and Administrative Expenses	—		10		(10		)	(100.0	)%
Total Company General and Administrative Expense	$	30	$	28	$	2		7.1	%

Overall, total Company General and Administrative Expenses have increased $2 million in the period-to-period comparison. This was primarily due to a contingent charitable contribution agreement with the Boy Scouts of America that was entered into in 2010. The final $6 million of the contribution was recognized during the three months ended March 31, 2014, as the conditions were met. The remaining $4 million improvement was due to reduced staffing and cost control projects following the sale of the five West Virginia coal mines in December 2013.

Total Company long-term liabilities for continuing operations, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Total CONSOL Energy continuing operations expense related to our actuarial liabilities was $28 million for the three months ended March 31, 2014 compared to $59 million for the three months ended March 31, 2013. The decrease of $31 million for total CONSOL Energy continuing operations expense was primarily due to required pension settlement accounting which resulted in a $27 million increase of expense during 2013. Pension settlement expenses were required when lump sum distributions made for the 2013 plan year exceeded the total of the service cost and interest cost for the 2013 plan year. The pension settlement was not allocated to individual operating segments and is therefore not included in unit costs presented for E&P or Coal. See Note 3 - Pension and Other Post-Employment Benefit Plans and Note 4 - Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q for additional detail of the total Company expense decrease.

TOTAL E&P SEGMENT ANALYSIS for the three months ended March 31, 2014 compared to the three months ended March 31, 2013:

The E&P segment contributed $80 million to earnings before income tax for the three months ended March 31, 2014 compared to a loss before income tax of $1 million in the three months ended March 31, 2013.



	For the Three Months Ended												Difference to Three Months Ended
	March 31, 2014												March 31, 2013
(in millions)	Marcellus		CBM		Shallow Oil and Gas			Other Gas			Total E&P		Marcellus		CBM			Shallow Oil and Gas			Other Gas			Total E&P
Sales:
Produced	$	125	$	95	$	32		$	13		$	265	$	77	$	12		$	—		$	8		$	97
Related Party	—		2		—			—			2		—		1			—			—			1
Total Outside Sales	125		97		32			13			267		77		13			—			8			98
Gas Royalty Interest	—		—		—			26			26		—		—			—			12			12
Purchased Gas	—		—		—			4			4		—		—			—			3			3
Other Income	—		—		—			34			34		—		—			—			21			21
Total Revenue and Other Income	125		97		32			77			331		77		13			—			44			134
Lifting	9		9		8			3			29		4		—			1			2			7
Ad Valorem, Severance, and Other Taxes	3		3		3			1			10		2		2			—			1			5
Gathering	18		26		8			2			54		9		(2		)	(2		)	1			6
E&P Direct Administrative, Selling & Other	8		2		1			1			12		2		—			(1		)	—			1
Depreciation, Depletion and Amortization	28		23		14			7			72		15		—			—			4			19
General & Administration	—		—		—			17			17		—		—			—			7			7
Gas Royalty Interest	—		—		—			23			23		—		—			—			11			11
Purchased Gas	—		—		—			3			3		—		—			—			2			2
Exploration and Other Costs	—		—		—			3			3		—		—			—			(7		)	(7		)
Other Corporate Expenses	—		—		—			26			26		—		—			—			2			2
Interest Expense	—		—		—			2			2		—		—			—			—			—
Total Cost	66		63		34			88			251		32		—			(2		)	23			53
Earnings Before Income Tax	$	59	$	34	$	(2	)	$	(11	)	$	80	$	45	$	13		$	2		$	21		$	81

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $59 million to the total Company earnings before income tax for the three months ended March 31, 2014 compared to $14 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
	2014			2013		Variance			Percent Change
Marcellus Gas Sales Volumes (Bcf)	19.2			10.2		9.0			88.2	%
NGLs Sales Volumes (Bcfe)*	1.3			0.4		0.9			225.0	%
Condensate Sales Volumes (Bcfe)*	0.2			0.1		0.1			100.0	%
Total Marcellus Gas Sales Volumes (Bcfe)*	20.7			10.7		10.0			93.5	%

Average Sales Price - Gas (Mcf)	$	6.12		$	3.70	$	2.42		65.4	%
Hedging Impact - Gas (Mcf)	$	(0.30	)	$	0.60	$	(0.90	)	(150.0	)%
Average Sales Price - NGLs (Mcfe)*	$	8.33		$	8.37	$	(0.04	)	(0.5	)%
Average Sales Price - Condensate (Mcfe)*	$	12.06		$	13.60	$	(1.54	)	(11.3	)%

Total Average Marcellus sales (per Mcfe)	$	6.03		$	4.53	$	1.50		33.1	%
Average Marcellus lifting costs (per Mcfe)	$	0.42		$	0.46	$	(0.04	)	(8.7	)%
Average Marcellus ad valorem, severance, and other taxes (per Mcfe)	$	0.14		$	0.13	$	0.01		7.7	%
Average Marcellus gathering costs (per Mcfe)	$	0.88		$	0.84	$	0.04		4.8	%
Average Marcellus direct administrative, selling & other costs (per Mcfe)	$	0.38		$	0.57	$	(0.19	)	(33.3	)%
Average Marcellus depreciation, depletion and amortization costs (per Mcfe)	$	1.36		$	1.24	$	0.12		9.7	%
Total Average Marcellus costs (per Mcfe)	$	3.18		$	3.24	$	(0.06	)	(1.9	)%
Average Margin for Marcellus (per Mcfe)	$	2.85		$	1.29	$	1.56		120.9	%

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

The Marcellus segment sales revenues were $125 million for the three months ended March 31, 2014 compared to $48 million for the three months ended March 31, 2013. The $77 million increase is primarily due to a 93.5% increase in total volumes sold, and a 65.4% increase 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 increase in Marcellus total average sales price was primarily the result of the $2.42 per Mcf increase in gas market prices, along with an additional 1.0 Bcfe of natural gas liquids and condensate sales volumes. The increase was offset, in part, by a $0.90 per Mcf decrease resulting from various transactions from our hedging program. These financial hedges represented approximately 14.0 Bcf of our produced Marcellus gas sales volumes for the three months ended March 31, 2014 at an average price of $4.73 per Mcf. For the three months ended March 31, 2013, these financial hedges represented approximately 4.3 Bcf at an average price of $4.75 per Mcf.

Total costs for the Marcellus segment were $66 million for the three months ended March 31, 2014 compared to $34 million for the three months ended March 31, 2013. The increase in total dollars and decrease in unit costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $9 million for the three months ended March 31, 2014 compared to $5 million for the three months ended March 31, 2013. The increase in total dollars primarily relates to additional volumes sold and an increase in salt water disposal, road maintenance, and well tending costs. The increase in total dollars were more than offset by the increase in gas sales volumes and resulted in an improvement in unit costs.

•Marcellus ad valorem, severance and other taxes were $3 million for the three months ended March 31, 2014 compared to $1 million for the three months ended March 31, 2013. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by the 65.4% increase in average gas sales prices and the 93.5% increase in sales volumes during the current period.

•Marcellus gathering costs were $18 million for the three months ended March 31, 2014 compared to $9 million for the three months ended March 31, 2013. Total dollars increased primarily due to an increase in processing fees associated with natural gas liquids along with an increase in utilized firm transportation costs, which resulted in a $0.08 per Mcfe increase in average unit costs. The impact on average unit costs from this increase was offset by higher sales volumes.

•Marcellus direct administrative, selling and other costs were $8 million for the three months ended March 31, 2014 compared to $6 million for the three months ended March 31, 2013. Direct administrative, selling and other costs attributable to the total E&P divisions are allocated to the individual E&P segments based on a combination of capital, production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The decrease in unit costs was primarily due to the increase in volumes sold.

•Depreciation, depletion and amortization costs were $28 million for the three months ended March 31, 2014 compared to $13 million for the three months ended March 31, 2013. 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 in the three months ended March 31, 2014. There was approximately $12 million, or $1.21 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, 2013. There was approximately $1 million, or $0.03 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended March 31, 2014 and for the three months ended March 31, 2013.

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $34 million to the total Company earnings before income tax for the three months ended March 31, 2014 compared to $21 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
	2014			2013		Variance			Percent Change
CBM Gas Sales Volumes (Bcf)	19.8			20.7		(0.9		)	(4.3	)%

Average Sales Price - Gas (Mcf)	$	5.31		$	3.56	$	1.75		49.2	%
Hedging Impact - Gas (Mcf)	$	(0.41	)	$	0.51	$	(0.92	)	(180.4	)%

Total Average CBM sales price (per Mcf)	$	4.90		$	4.08	$	0.82		20.1	%
Average CBM lifting costs (per Mcf)	$	0.47		$	0.45	$	0.02		4.4	%
Average CBM ad valorem, severance, and other taxes (per Mcf)	$	0.18		$	0.06	$	0.12		200.0	%
Average CBM gathering costs (per Mcf)	$	1.30		$	1.39	$	(0.09	)	(6.5	)%
Average CBM direct administrative, selling & other costs (per Mcf)	$	0.11		$	0.08	$	0.03		37.5	%
Average CBM depreciation, depletion and amortization costs (per Mcf)	$	1.14		$	1.08	$	0.06		5.6	%
Total Average CBM costs (per Mcf)	$	3.20		$	3.06	$	0.14		4.6	%
Average Margin for CBM (per Mcf)	$	1.70		$	1.02	$	0.68		66.7	%

CBM sales revenues were $97 million in the three months ended March 31, 2014 compared to $84 million for the three months ended March 31, 2013. The $13 million increase was primarily due to a 20.1% increase in total average sales price per Mcf offset, in part, by a 4.3% decrease in total volumes sold. CBM sales volumes decreased 0.9 Bcf for the three months ended March 31, 2014 compared to the 2013 period. The decrease was primarily due to normal well declines and the extreme cold weather in the first quarter of 2014, which reduced production by causing some wells to freeze up. The CBM total average sales price increased $1.75 due to an increase in gas market prices. The increase was offset, in part, by a $0.92 per Mcf decrease due to various transactions from our hedging program. Financial hedges represented approximately 16.7 Bcf of our produced CBM gas sales volumes for the three months ended March 31, 2014 at an average price of $4.41 per Mcf. For the three months ended March 31, 2013, these financial hedges represented approximately 9.1 Bcf at an average price of $4.63 per Mcf.

Total costs for the CBM segment were $63 million for the three months ended March 31, 2014 and March 31, 2013. The increase in unit costs for the CBM segment was due to the following items:

•CBM lifting costs were $9 million for the three months ended March 31, 2014 and March 31, 2013. The increase in unit costs was due to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $3 million for the three months ended March 31, 2014 compared to $1 million for the three months ended March 31, 2013. The increase of $2 million was due to an increase in severance tax expense resulting from the increase in average sales price, without the impact of hedging, as described above. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•CBM gathering costs were $26 million for the three months ended March 31, 2014 compared to $28 million for the three months ended March 31, 2013. The decrease in total dollars and average per unit costs was due to decreased well tending service costs, decreased power fees, and a decrease in transportation costs. Improvements in unit costs were offset, in part, by the decrease in gas sales volumes.

•CBM direct administrative, selling and other costs were $2 million for the three months ended March 31, 2014 and March 31, 2013. Unit costs were negatively impacted by the decrease in gas sales volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $23 million for the three months ended March 31, 2014 and March 31, 2013. There was approximately $16 million, or $0.78 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, 2014. The production portion of depreciation, depletion and amortization was $15 million, or $0.75 per unit-of-production in the three months ended March 31, 2013. There was approximately $7 million, or $0.36 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended March 31, 2014. The non-production related depreciation, depletion and amortization was $8 million, or $0.33 per Mcf for the three months ended March 31, 2013.

SHALLOW OIL AND GAS SEGMENT

The shallow oil and gas segment had a loss before income tax of $2 million for the three months ended March 31, 2014 compared to a loss before income tax of $4 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
	2014			2013			Variance			Percent Change
Shallow Oil and Gas Sales Volumes (Bcf)	5.7			7.0			(1.3		)	(18.6	)%
Oil Sales Volumes (Bcfe)*	0.1			0.1			—			—	%
Total Shallow Oil and Gas Sales Volumes (Bcfe)*	5.8			7.1			(1.3		)	(18.3	)%

Average Sales Price - Gas (Mcf)	$	5.72		$	3.50		$	2.22		63.4	%
Hedging Impact - Gas (Mcf)	$	(0.30	)	$	0.99		$	(1.29	)	(130.3	)%
Average Sales Price - Oil (Mcfe)*	$	14.45		$	10.00		$	4.45		44.5	%

Total Average Shallow Oil and Gas sales price (per Mcfe)	$	5.57		$	4.57		$	1.00		21.9	%
Average Shallow Oil and Gas lifting costs (per Mcfe)	$	1.29		$	1.00		$	0.29		29.0	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes (per Mcfe)	$	0.51		$	0.38		$	0.13		34.2	%
Average Shallow Oil and Gas gathering costs (per Mcfe)	$	1.46		$	1.41		$	0.05		3.5	%
Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)	$	0.17		$	0.32		$	(0.15	)	(46.9	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs (per Mcfe)	$	2.44		$	2.03		$	0.41		20.2	%
Total Average Shallow Oil and Gas costs (per Mcfe)	$	5.87		$	5.14		$	0.73		14.2	%
Average Margin for Shallow Oil and Gas (per Mcfe)	$	(0.30	)	$	(0.57	)	$	0.27		(47.4	)%

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

Shallow Oil and Gas sales revenues were $32 million for the three months ended March 31, 2014 and for the three months ended March 31, 2013. There was an 18.3% decrease in total volumes sold, offset, in part, by a 21.9% increase in the total average sales price. The decrease in total volumes sold was primarily due to normal well declines, along with the extreme cold weather conditions that occurred in the first quarter of 2014. The cold weather was responsible for wells freezing up, which in turn reduced production capabilities. The increase in shallow oil and gas total average sales price was primarily the result of a $2.22 per Mcf increase in average market prices offset by a $1.29 per Mcf decrease due to various transactions from our hedging program. These financial hedges represented approximately 3.6 Bcf of our produced shallow oil and gas sales volumes for the three months ended March 31, 2014 at an average price of $4.64 per Mcf. For the three months ended March 31, 2013, these financial hedges represented approximately 3.3 Bcf at an average price of $5.28 per Mcf.

Total costs for the shallow oil and gas segment were $34 million for the three months ended March 31, 2014 compared to $36 million for the three months ended March 31, 2013. The decrease in total dollars and increase in unit costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $8 million for the three months ended March 31, 2014 compared to $7 million for the three months ended March 31, 2013. The $1 million increase in total costs and $0.29 per Mcfe increase in average unit costs is due to an increase in accretion expense on the well plugging liability and an increase in well tending costs offset, in part, by lower repair and maintenance costs. Unit costs were also negatively impacted by the decrease in gas sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes remained consistent at $3 million for the three months ended March 31, 2014 and March 31, 2013. The increase of $0.13 per Mcfe in unit costs was primarily due to the increase in sales price along with the decrease in sales volumes.

•Shallow Oil and Gas gathering costs were $8 million for the three months ended March 31, 2014 compared to $10 million for the three months ended March 31, 2013. Gathering costs decreased $2 million primarily due to a decrease in firm transportation costs in the period-to-period comparison. The decrease in total dollars was more than offset by the decrease in gas sales volumes, which resulted in an impairment in unit costs.

•Shallow Oil and Gas direct administrative, selling and other costs were $1 million for the three months ended March 31, 2014 compared to $2 million for the three months ended March 31, 2013. The $1 million decrease in the period-to-period comparison was due to Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. These decreases in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $14 million for the three months ended March 31, 2014 and March 31, 2013. There was approximately $12 million, or $2.14 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2014. There was approximately $12 million, or $1.79 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended March 31, 2013. There was approximately $2 million, or $0.30 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended March 31, 2014. There was $2 million, or $0.24 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended March 31, 2013.

OTHER GAS SEGMENT

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

Other gas sales volumes are primarily related to production from the the Utica Shale in Ohio and the Chattanooga Shale in Tennessee. Revenue from these operations was approximately $13 million for the three months ended March 31, 2014 and $5 million for the three months ended March 31, 2013. Total costs related to these other sales were $14 million for the three months ended March 31, 2014 compared to $6 million for the three months ended March 31, 2013. A per unit analysis of the other operating costs in the Utica Shale and the Chattanooga Shale is not meaningful due to the relatively low volumes sold in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas sales revenue was $26 million for the three months ended March 31, 2014 compared to $14 million for the three months ended March 31, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.



	For the Three Months Ended March 31,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.2		3.5		0.7		20.0	%
Average Sales Price Per thousand cubic feet	$	6.33	$	4.10	$	2.23	54.4	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $4 million for the three months ended March 31, 2014 and $1 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
	2014		2013		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.4		0.4		—		—	%
Average Sales Price Per thousand cubic feet	$	9.67	$	3.45	$	6.22	180.3	%

Other income was $34 million for the three months ended March 31, 2014 compared to $13 million for the three months ended March 31, 2013. The $21 million change was primarily due to the following items:


•	Earnings from our equity affiliates increased $3 million due to various items that occurred throughout both periods, none of which were individually material.


•	Other income increased $14 million due to an increase in revenue related to certain gathering arrangements.


•	Gains on dispositions of non-core acreage and equipment increased $3 million due to various transactions that occurred throughout both periods, none of which are individually material.


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


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

General and Administrative costs are allocated to the total E&P segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $17 million for the three months ended March 31, 2014 compared to $10 million for the three months ended March 31, 2013. Refer to the discussion of total Company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this quarterly report for a detailed cost explanation.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy E&P segment. Royalty interest gas costs were $23 million for the three months ended March 31, 2014 compared to $12 million for the three months ended March 31, 2013. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended March 31,
	2014		2013		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	4.2		3.5		0.7		20.0	%
Average Cost Per thousand cubic feet sold	$	5.49	$	3.41	$	2.08	61.0	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that CONSOL Energy sells. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $3 million for the three months ended March 31, 2014 and $1 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
	2014		2013		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.4		0.4		—		—	%
Average Cost Per thousand cubic feet sold	$	8.12	$	2.44	$	5.68	232.8	%

Exploration and other costs were $3 million for the three months ended March 31, 2014 compared to $10 million for the three months ended March 31, 2013. The $7 million decrease is due to the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance			Percent Change
Marcellus Title Defects	$	—	$	6	$	(6	)	(100.0	)%
Exploration	2		3		(1		)	(33.3	)%
Lease Expiration Costs	1		1		—			—	%
Total Exploration and Other Costs	$	3	$	10	$	(7	)	(70.0	)%


•	CONSOL Energy, working in collaboration with Noble Energy, conceded title defects on acreage which had a book value of $6 million for the three months ended March 31, 2013.


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


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

Other corporate expenses were $26 million for the three months ended March 31, 2014 compared to $24 million for the three months ended March 31, 2013. The $2 million increase in the period-to-period comparison was made up of the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance			Percent Change
Unutilized firm transportation	$	10	$	7	$	3		42.9	%
Short term incentive compensation	6		5		1			20.0	%
Bank fees	2		2		—			—	%
Stock-based compensation	6		9		(3		)	(33.3	)%
Other	2		1		1			100	%
Total Other Corporate Expenses	$	26	$	24	$	2		8.3	%


•	Unutilized firm transportation costs represent pipeline transportation capacity the E&P segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The $3 million increase is due to increased firm transportation capacity which has not been utilized by active operations.


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


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


•	Stock-based compensation decreased $3 million in the period-to-period comparison primarily due to a reduction in the non-cash amortization expense and less accelerated expense for retiree eligible employees under our current plans.


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

Interest expense related to the gas segment remained consistent at $2 million for the three months ended March 31, 2014 and March 31, 2013.

TOTAL COAL SEGMENT ANALYSIS for the three months ended March 31, 2014 compared to the three months ended March 31, 2013:

The coal segment contributed $107 million of earnings before income tax in the three months ended March 31, 2014 compared to $100 million in the three months ended March 31, 2013. Variances by the individual coal segments are discussed below.



	For the Three Months Ended														Difference to Three Months Ended
	March 31, 2014														March 31, 2013
(in millions)	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	417		$	28	$	85		$	—		$	530		$	71		$	(21	)	$	(62	)	$	—		$	(12	)
Purchased Coal	—			—		—			5			5			—			—			—			(1		)	(1		)
Total Outside Sales	417			28		85			5			535			71			(21		)	(62		)	(1		)	(13		)
Freight Revenue	—			—		—			10			10			—			—			—			(2		)	(2		)
Other Income	—			1		—			24			25			—			—			—			11			11
Total Revenue and Other Income	417			29		85			39			570			71			(21		)	(62		)	8			(4		)
Costs and Expenses:
Beginning inventory costs	21			—		11			—			32			(12		)	—			(10		)	—			(22		)
Total direct operating costs	171			12		48			37			268			14			(14		)	—			(12		)	(12		)
Total royalty/production taxes	19			2		5			—			26			(2		)	2			(2		)	—			(2		)
Total direct services to operations	27			2		6			42			77			(3		)	(3		)	—			28			22
Total retirement and disability	18			2		6			—			26			2			(1		)	(1		)	(3		)	(3		)
Depreciation, depletion and amortization	32			2		10			12			56			3			(3		)	(1		)	—			(1		)
Ending inventory costs	(20		)	—		(12		)	—			(32		)	13			—			(4		)	—			9
Total Costs and Expenses	268			20		74			91			453			15			(19		)	(18		)	13			(9		)
Freight Expense	—			—		—			10			10			—			—			—			(2		)	(2		)
Total Costs	268			20		74			101			463			15			(19		)	(18		)	11			(11		)
Earnings (Loss) Before Income Taxes	$	149		$	9	$	11		$	(62	)	$	107		$	56		$	(2	)	$	(44	)	$	(3	)	$	7

THERMAL COAL SEGMENT

The thermal coal segment contributed $149 million to total Company earnings before income tax for the three months ended March 31, 2014 and $93 million for the three months ended March 31, 2013. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended March 31,
	2014		2013		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	6.4		5.4		1.0			18.5	%
Average Sales Price Per Thermal Ton Sold	$	65.17	$	64.47	$	0.70		1.1	%

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

Total Direct Operating Costs Per Thermal Ton Produced	$	26.58	$	29.31	$	(2.73	)	(9.3	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	2.99		3.84		(0.85		)	(22.1	)%
Total Direct Services to Operations Per Thermal Ton Produced	4.19		5.64		(1.45		)	(25.7	)%
Total Retirement and Disability Per Thermal Ton Produced	2.74		2.88		(0.14		)	(4.9	)%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	4.95		5.46		(0.51		)	(9.3	)%
Total Production Costs Per Thermal Ton Produced	$	41.45	$	47.13	$	(5.68	)	(12.1	)%

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

Total Costs Per Thermal Ton Sold	$	41.91	$	47.13	$	(5.22	)	(11.1	)%
Average Margin Per Thermal Ton Sold	$	23.26	$	17.34	$	5.92		34.1	%

Thermal coal revenue was $417 million for the three months ended March 31, 2014 compared to $346 million for the three months ended March 31, 2013. The $71 million increase was attributable to a 1.0 million increase in tons sold and a $0.70 per ton higher average sales price. The increase in price was partially due to 0.5 million tons of thermal coal being priced on the export market at an average sales price of $61.48 per ton for the three months ended March 31, 2014 compared to 0.6 million tons at an average price of $59.15 per ton for the three months ended March 31, 2013.

Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. The costs of tons produced include items such as direct operating costs, royalty and production taxes, direct services to operations, retirement and disability, and depreciation, depletion, and amortization costs. Total cost of goods sold for thermal coal was $268 million for the three months ended March 31, 2014, or $15 million higher than the $253 million for the three months ended March 31, 2013. Total cost of goods sold for thermal coal was $41.91 per ton in the three months ended March 31, 2014 compared to $47.13 per ton in the three months ended March 31, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 18.5% increase in thermal tons sold. Fixed costs are allocated over more tons, resulting in lower unit costs.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $9 million to total Company earnings before income tax for the three months ended March 31, 2014 compared to $11 million for the three months ended March 31, 2013. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended March 31,
	2014		2013			Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.5		0.7			(0.2		)	(28.6	)%
Average Sales Price Per High Vol Met Ton Sold	$	56.35	$	69.10		$	(12.75	)	(18.5	)%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	25.33	$	36.74		$	(11.41	)	(31.1	)%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	3.07		(0.07		)	3.14			4,485.7	%
Total Direct Services to Operations Per High Vol Met Ton Produced	3.62		7.50			(3.88		)	(51.7	)%
Total Retirement and Disability Per High Vol Met Ton Produced	2.73		3.60			(0.87		)	(24.2	)%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.06		6.87			(1.81		)	(26.3	)%
Total Production Costs Per High Vol Met Ton Produced	$	39.81	$	54.64		$	(14.83	)	(27.1	)%

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

Total Costs Per High Vol Met Ton Sold	$	39.81	$	54.64		$	(14.83	)	(27.1	)%
Margin Per High Vol Met Ton Sold	$	16.54	$	14.46		$	2.08		14.4	%

High volatile metallurgical coal revenue was $28 million for the three months ended March 31, 2014 compared to $49 million for the three months ended March 31, 2013. Average sales prices for high volatile metallurgical coal decreased $12.75 per ton in the period-to-period comparison. CONSOL Energy priced 0.5 million tons of high volatile metallurgical coal in the export market at an average sales price of $56.35 per ton for the three months ended March 31, 2014 compared to 0.6 million tons at an average price of $65.95 per ton for the three months ended March 31, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

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

Total cost of goods sold for high volatile metallurgical coal was $20 million for the three months ended March 31, 2014, or $19 million lower than the $39 million for the three months ended March 31, 2013. Total cost of goods sold for high volatile metallurgical coal was $39.81 per ton in the three months ended March 31, 2014 compared to $54.64 per ton in the three months ended March 31, 2013. The decrease in total dollars and unit costs is due to the mix of mines which sold tons in the current period. Our lower cost Bailey and Enlow Fork mines sold all tons in this segment in 2014 compared to approximately 90% of the high volatile metallurgical coal tons sold in 2013.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $11 million to total Company earnings before income tax in the three months ended March 31, 2014 compared to $55 million in the three months ended March 31, 2013. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Three Months Ended March 31,
	2014		2013		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	1.1		1.4		(0.3		)	(21.4	)%
Average Sales Price Per Low Vol Met Ton Sold	$	76.80	$	102.69	$	(25.89	)	(25.2	)%

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

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	41.65	$	37.83	$	3.82		10.1	%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	4.57		5.62		(1.05		)	(18.7	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	5.86		4.70		1.16			24.7	%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.70		5.18		0.52			10.0	%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.57		8.40		0.17			2.0	%
Total Production Costs Per Low Vol Met Ton Produced	$	66.35	$	61.73	$	4.62		7.5	%

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

Total Costs Per Low Vol Met Ton Sold	$	66.41	$	64.42	$	1.99		3.1	%
Margin Per Low Vol Met Ton Sold	$	10.39	$	38.27	$	(27.88	)	(72.9	)%

Low volatile metallurgical coal revenue was $85 million for the three months ended March 31, 2014 compared to $147 million for the three months ended March 31, 2013. The $62 million decrease was attributable to a $25.89 per ton lower average sales price and a 0.3 million decrease in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. CONSOL Energy priced 0.9 million tons of low volatile metallurgical coal in the export market at an average sales price of $70.83 per ton for the three months ended March 31, 2014 compared to 1.1 million tons at an average price of $89.90 per ton for the three months ended March 31, 2013. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold for low volatile metallurgical coal was $74 million for the three months ended March 31, 2014, or $18 million lower than the $92 million for the three months ended March 31, 2013. Total cost of goods sold for low volatile metallurgical coal was $66.41 per ton in the three months ended March 31, 2014 compared to $64.42 per ton in the three months ended March 31, 2013. The decrease in total dollars and increase in unit costs per low volatile metallurgical ton was primarily due to the decrease in tons sold and lower royalties and production taxes which are related to lower sales prices.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $62 million for the three months ended March 31, 2014 compared to a loss before income tax of $59 million for the three months ended March 31, 2013. The other coal segment includes purchased coal activities, idle mine activities, as well as various activities assigned to the coal segment but not allocated to each individual mine.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications and coal purchased from third parties and sold directly to our customers. The revenues were $5 million for the three months ended March 31, 2014 compared to $6 million for the three months ended March 31, 2013.

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset by freight expense. Freight revenue was $10 million for the three months ended March 31, 2014 compared to $12 million for the three months ended March 31, 2013. The $2 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $24 million for the three months ended March 31, 2014 compared to $13 million for the three months ended March 31, 2013. The change is due to the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance
Rental Income	$	14	$	1	$	13
Equity in earnings of affiliates	3		1		2
Royalty Income	5		4		1
Business Interruption Proceeds - Bailey Mine	—		3		(3		)
Other	2		4		(2		)
Total Other Income Coal Segment	$	24	$	13	$	11


•	Rental income increased $13 million due to equipment leased and equipment subleased to a third-party. These arrangements began in December 2013.


•	Equity in earnings of affiliates increased $2 million due to earnings from our equity affiliates.


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


•	In the three months ended March 31, 2013, $3 million of business interruption proceeds were received related to the 2012 Bailey Belt Conveyor accident.


•	The remaining $2 million decrease is due to various items, none of which were individually significant.

Other coal segment total costs were $101 million for the three months ended March 31, 2014 compared to $90 million for the three months ended March 31, 2013. The increase of $11 million was primarily due to the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance
Lease Rental Expense	$	12	$	1	$	11
General and Administrative Expense	12		9		3
Stock-based and Incentive Compensation	19		19		—
Closed and Idle Mines	23		24		(1		)
Freight Expense	10		12		(2		)
Purchased Coal	7		11		(4		)
Other	18		14		4
Total Other Coal Segment Costs	$	101	$	90	$	11


•	Lease rental expense increased $11 million primarily due to equipment leases that are subleased to a third-party. The third-party subleases began in December 2013.


•	General and Administrative Expense related to the other coal segment increased by $3 million primarily due to various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section "Net Income" of this quarterly report for detailed cost explanations.


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


•	Closed and idle mine costs decreased approximately $1 million due to various items that occurred throughout both periods, none of which were individually material.

•

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


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


•	Other expenses related to the Other Coal segment increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.

OTHER SEGMENT ANALYSIS for the three months ended March 31, 2014 compared to the three months ended March 31, 2013:

The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $63 million for the three months ended March 31, 2014 compared to a loss before income tax of $103 million for the three months ended March 31, 2013. The other segment also includes total Company income tax expense of $8 million for the three months ended March 31, 2014 compared to an income tax benefit of $1 million for the three months ended March 31, 2013.



	For the Three Months Ended March 31,
(in millions)	2014			2013			Variance			Percent Change
Sales—Outside	69			69			$	—		—	%
Other Income	1			3			(2		)	(66.7	)%
Total Revenue	70			72			(2		)	(2.8	)%
Cost of Goods Sold and Other Charges	75			123			(48		)	(39.0	)%
Depreciation, Depletion & Amortization	1			2			(1		)	(50.0	)%
Interest Expense	49			51			(2		)	(3.9	)%
Total Costs	125			176			(51		)	(29.0	)%
Loss Before Income Tax	(55		)	(104		)	49			(47.1	)%
Income Tax	8			(1		)	9			(900.0	)%
Net Loss	$	(63	)	$	(103	)	$	40		(38.8	)%

Industrial supplies:

Outside Sales from industrial supplies were $59 million for the three months ended March 31, 2014 compared to $54 million for the three months ended March 31, 2013. The increase of $5 million was primarily related to higher sales volumes.

Total costs related to industrial supply sales were $59 million for the three months ended March 31, 2014 compared to $54 million for the three months ended March 31, 2013. The increase of $5 million was primarily related to higher sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Outside Sales from transportation operations were $10 million for the three months ended March 31, 2014 compared to $15 million for the three months ended March 31, 2013. The decrease of $5 million was primarily attributable to decreased thru-put as well as lower per ton thru-put rates for the quarter.

Total costs related to the transportation operations were $8 million for the three months ended March 31, 2014 compared to $9 million for the three months ended March 31, 2013. Costs decreased $1 million due to lower per ton thru-put costs and a decrease in thru-put volumes.

Miscellaneous other:

Additional other income of $1 million was recognized for the three months ended March 31, 2014 compared to $3 million for the three months ended March 31, 2013. The $2 million decrease is due to various items in both periods, none of which were individually material.

Other corporate costs were $58 million for the three months ended March 31, 2014 compared to $113 million for the three months ended March 31, 2013. Other corporate costs decreased due to the following items:



	For the Three Months Ended March 31,
(in millions)	2014		2013		Variance
Pension Settlement	$	—	$	27	$	(27	)
CNX Gas shareholder settlement	—		20		$	(20	)
Interest Expense	49		51		$	(2	)
Bank Fees	4		3		$	1
Other	5		12		$	(7	)
	$	58	$	113	$	(55	)


•	Pension settlement expenses were required when the lump sum distributions made for the 2013 plan year exceeded the total of the service and interest costs for the 2013 plan year.

•

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


•	Interest expense decreased $2 million primarily due to the IRS audit resolution causing a reduction to anticipated interest as discussed in Note 5 - Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q.


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


•	Other corporate items decreased $7 million primarily due to various transactions that occurred throughout both periods, none of which were individually material.

Income Taxes:

The effective income tax rate was 6.5% for the three months ended March 31, 2014 compared to 19.3% for the three months ended March 31, 2013. The effective rates for the three months ended March 31, 2014 and 2013 were calculated using the annual effective rate projections on recurring earnings and include tax liabilities related to certain discrete transactions. For the three months ended March 31, 2014, CONSOL Energy also recognized certain tax benefits as a result of changes in estimates related to a prior-year tax provision. There was a tax benefit of $8 million related to increased percentage depletion deductions, offset, in part, by $0.6 million of tax expense due to changes in the Domestic Production Activities Deduction and various other estimates. Also, the Internal Revenue Service has issued its audit report relating to the examination of CONSOL Energy’s 2008 and 2009 U.S. income tax returns during the three months ended March 31, 2014. The result of these findings was a change in timing of certain tax deductions which increased the tax benefit of percentage depletion by $9 million in tax years 2008 and 2009. The company also recognized additional tax benefits of $1 million primarily related to an increase in the Domestic Production Activities Deduction for the audited periods. The relationship between pre-tax earnings and percentage depletion also impacts the effective tax rate. See Note 5 - 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)	2014			2013			Variance			Percent Change
Total Company Earnings Before Income Tax	$	130		$	(5	)	$	135		(2,924.6	)%
Income Tax Expense (Benefit)	$	8		$	(1	)	$	9		(1,009.0	)%
Effective Income Tax Rate	6.5		%	19.3		%	(12.8		)%

Liquidity and Capital Resources

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. CONSOL Energy's $1.0 billion Senior Secured Credit Agreement, as amended by Amendment No.1 dated December 5, 2013, expires April 12, 2016. The amendment on December 5, 2013 reduced the availability from $1.5 billion to $1.0 billion resulting in an acceleration of previously deferred financing charges of $3.2 million. 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 $1.0 billion of borrowings and letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing adjusted earnings before interest, taxes, depreciation, depletion and amortization (Adjusted EBITDA), measured quarterly. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. The facility includes a minimum interest coverage ratio covenant of no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. 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 2.52 to 1.00 at March 31, 2014. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates, excluding cash distributions from CNX Gas and its subsidiaries, plus pro-rata earnings from material acquisitions. The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio is calculated as the ratio of secured debt to Adjusted EBITDA. Secured debt is defined as financial covenant debt, excluding indebtedness not secured by a lien, of CONSOL Energy and certain of its subsidiaries. The senior secured leverage ratio was 0.00 to 1.00 at March 31, 2014. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another company and amend, modify or restate, in any material way, the senior unsecured notes. At March 31, 2014, the facility had no outstanding borrowings and $168 million of letters of credit outstanding, leaving $832 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. The Company negotiated a reduced capacity on this arrangement from $200 million to $125 million during the first quarter of 2014. This facility allows the Company to receive, on a revolving basis, 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, 2014, eligible accounts receivable totaled approximately $98.5 million. At March 31, 2014, the facility had no outstanding borrowings and $62 million of letters of credit outstanding, leaving $36 million of unused capacity.

CNX Gas' $1.0 billion Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0 billion for borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 35.48 to 1.00 at March 31, 2014. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The leverage ratio is calculated as the ratio of financial covenant debt to twelve-month trailing Adjusted EBITDA for CNX Gas and its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, for CNX Gas and its subsidiaries. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.42 to 1.00 at March 31, 2014. Covenants in the facility limit CNX Gas' ability to

dispose of assets, make investments, pay dividends and merge with another company. The credit facility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for $600 million of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. At March 31, 2014, the facility had no outstanding borrowings and $95 million of letters of credit outstanding, leaving $905 million of unused capacity.

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

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap and option transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $15 million at March 31, 2014. The ineffective portion of these contracts was insignificant to earnings during the three months ended March 31, 2014. No issues related to our hedge agreements have been encountered to date.

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

Cash Flows (in millions)



	For the Three Months Ended March 31,
	2014			2013			Change
Cash flows from operating activities	$	336		$	268		$	68
Cash used in investing activities	$	(335	)	$	(232	)	$	(103	)
Cash used in financing activities	$	(14	)	$	(34	)	$	20

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


•	Net income increased $118 million in the period-to-period comparison.


•	Changes in discontinued operations income (loss) as well as working capital adjustments.


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

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


•	Capital expenditures from continuing operations increased $101 million in the period-to-period comparison due to:


◦	Coal segment capital expenditures increased $46 million. The increase was comprised of $75 million for the acquisition of the BMX longwall shields. The increase was offset by a $12 million decrease in the Enlow Fork Overland Belt Project, which was completed in February 2014 and $17 million decrease in various other projects none of which were individually material.


◦	Gas segment capital expenditures increased $59 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays and various other individually insignificant projects;


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


•	Proceeds from the sale of assets, continuing operations, increased $51 million in the period-to-period comparison due to:


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


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


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


◦	$1 million decrease due to various other transactions that occurred throughout both periods, none of which were individually material.

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


•	Net investments in equity affiliates decreased $3 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Restricted cash decreased $48 million due to the release of cash which is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012.


•	Discontinued Operations decreased $8 million due to the sale of certain facilities in December 2013.

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


•	In three months ended March 31, 2014, CONSOL Energy repaid $5 million of borrowings related to miscellaneous borrowings. In the three months ended March 31, 2013, CONSOL Energy repaid $27 million of borrowings.


•	There were $14 million of dividends paid in the three months ended March 31, 2014. The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in three months ended March 31, 2013.


•	In three months ended March 31, 2014, CONSOL Energy received $5 million due to the issuance of common stock as compared to $1 million received by the issuance of common stock in 2013.


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

The following is a summary of our significant contractual obligations at March 31, 2014 (in thousands):



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Purchase Order Firm Commitments	$	86,881	$	125,569	$	58,758	$	10,978	$	282,186
Gas Firm Transportation	94,940		205,043		201,491		776,465		1,277,939
Long-Term Debt	3,512		6,605		1,503,256		1,605,314		3,118,687
Interest on Long-Term Debt	245,363		490,548		310,243		229,191		1,275,345
Capital (Finance) Lease Obligations	8,546		15,231		13,236		17,699		54,712
Interest on Capital (Finance) Lease Obligations	3,466		5,287		3,556		1,752		14,061
Operating Lease Obligations	102,832		187,556		141,571		67,919		499,878
Long-Term Liabilities—Employee Related (a)	88,463		182,376		187,384		788,555		1,246,778
Other Long-Term Liabilities (b)	335,332		214,046		80,962		325,464		955,804
Total Contractual Obligations (c)	$	969,335	$	1,432,261	$	2,500,457	$	3,823,337	$	8,725,390

_________________________


(a)	Long-Term Liabilities - Employee Related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the payout table due to the uncertainty regarding amounts to be contributed. Estimated 2014 contributions are expected to approximate $24 million.


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


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

Debt

At March 31, 2014, CONSOL Energy had total long-term debt and capital lease obligations of $3.173 billion outstanding, including the current portion of long-term debt of $12 million. This long-term debt consisted of:


•	An aggregate principal amount of $1.50 billion of 8.00% senior unsecured notes due in April 2017. 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 $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.


•	An aggregate principal amount of $250 million of 6.375% 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 $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 $10 million with an average interest rate of 7.93% per annum.


•	An aggregate principal amount of $5 million on other various rate notes maturing through June 2031.


•	An aggregate principal amount of $55 million of capital leases with a weighted average interest rate of 6.20% per annum.

At March 31, 2014, CONSOL Energy had no outstanding borrowings and had approximately $168 million of letters of credit outstanding under the $1.0 billion senior secured revolving credit facility. See Note 18 - Subsequent Event of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.

At March 31, 2014, CONSOL Energy had no outstanding borrowings and had $62 million of letters of credit outstanding under the accounts receivable securitization facility.

At March 31, 2014, CNX Gas, a wholly owned subsidiary of CONSOL Energy, had no outstanding borrowings and approximately $95 million of letters of credit outstanding under its $1.0 billion secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $5.1 billion at March 31, 2014 and $5.0 billion at December 31, 2013. Total equity increased primarily due to net income in the current period. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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



Declaration Date	Amount Per Share		Record Date	Payment Date
February 3, 2014	$	0.0625	February 14, 2014	February 28, 2014
April 30, 2014	$	0.0625	May 12, 2014	May 30, 2014

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 $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 4.62 to 1.00 and our availability was approximately $832 million at March 31, 2014. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 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, 2014.

Off-Balance Sheet Transactions

CONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Unaudited Consolidated Financial Statements of this Form 10-Q. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at March 31, 2014. The various multi-employer benefit plans are discussed in Note 18—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2013 Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the consolidated balance sheet at March 31, 2014. Management believes these items will expire without being funded. See Note 11—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional details of the various financial guarantees that have been issued by CONSOL Energy.

Forward-Looking Statements

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


•	deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;


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


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


•	our reliance on major customers;


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


•	the impacts of various asbestos litigation claims;


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


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


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


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


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


•	risks associated with our debt;


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


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


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


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


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


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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

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

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

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at March 31, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $67.2 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $69.9 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At March 31, 2014, CONSOL Energy had $3.173 billion aggregate principal amount of debt outstanding under fixed-rate instruments and no amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were no borrowings outstanding for the three months ended March 31, 2014. Also, CNX Gas did not have borrowings under its revolving credit facility for the three months ended March 31, 2014.

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

Hedging Volumes

As of April 9, 2014, our hedged volumes for the periods indicated are as follows:



	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2014 Fixed Price Volumes
Hedged Mcf	N/A		41,286,876		41,740,578		41,740,578		124,768,032
Weighted Average Hedge Price per thousand cubic feet	N/A		$	4.58	$	4.58	$	4.58	$	4.58
2015 Fixed Price Volumes
Hedged Mcf	19,579,760		19,797,313		20,014,866		20,014,866		79,406,805
Weighted Average Hedge Price per thousand cubic feet	$	4.06	$	4.06	$	4.06	$	4.06	$	4.06
2016 Fixed Price Volumes
Hedged Mcf	17,905,748		17,905,748		18,102,514		18,102,514		72,016,524
Weighted Average Hedge Price per thousand cubic feet	$	4.16	$	4.16	$	4.16	$	4.16	$	4.16


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

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

PART II: OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

The first through the ninth paragraphs of Note 11—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q are incorporated herein by reference.

ITEM 1A. RISK FACTORS

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, 2013, 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 (to be effective January 1, 2012, but currently subject to a stay ordering the agency to continue to enforce the Clean Air Interstate Rule (CAIR) promulgated in 2005 until a viable replacement to CSAPR can be issued, with an appeal of CSAPR currently pending before the U.S. Supreme Court) (On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit opinion vacating CSAPR. EPA is reviewing the opinion. At this time, CAIR remains in place and no immediate action from States or affected sources is expected.); 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 (to be effective April 16, 2015, depending on the outcome of a pending challenge in the D.C. Circuit Court of Appeals).

Another source of uncertainty is the consideration of regulation of coal ash disposal by the EPA. In June 2010, the EPA proposed new approaches for the regulation of Coal Combustion Residuals from electric generating facilities. The EPA is re-evaluating its August 1993 and May 2000 Bevill Regulatory Determinations that currently provide exemptions from the definition of hazardous wastes for certain materials. In October 2013, the U.S. District Court for the District of Columbia ordered the EPA to submit to the court a plan and schedule for finalizing coal ash rules under the Resource Conservation and Recovery Act (RCRA). In January 2014, EPA agreed in a court-ordered plan to take final action on its proposed coal ash disposal regulations by December 19, 2014.

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. Compliance with the Section 316(b) rule, which EPA must finalize by April 17, 2014 pursuant to a modified settlement agreement with Riverkeeper, is likely to impose substantial costs on our customers that operate power plants. Such costs could decrease demand for the coal and natural gas we produce.

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.

Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

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

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

We face uncertainties in estimating our economically recoverable natural gas and coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gas prices, production levels, reserve estimates and operating and development costs. As a result, estimated quantities of proved natural gas reserves and projections of future production rates and the timing of development expenditures may be incorrect. For example, a significant amount of our proved undeveloped reserves extensions and discoveries during the last three years were due to the addition of wells on our Marcellus Shale acreage more than one offset location away from existing production with reliable technology, which may be more susceptible to positive and negative changes in reserve estimates than our proved developed reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from reserve estimates. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved natural gas reserves on historical average prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:


•	geological conditions;


•	changes in governmental regulations and taxation;


•	the amount and timing of actual production;


•	assumptions governing future prices;


•	future operating costs; and


•	capital costs of drilling, completion and gathering assets.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10% discount rate of our proved natural gas reserves as of December 31, 2013 would decrease from $2.8 billion to $2.6 billion.

Similarly, there are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

• geologic conditions;

• historical production from the area compared with production from other producing areas;

• the assumed effects of regulations and taxes by governmental agencies;

• assumptions governing future prices; and

• future operating costs, including the cost of materials.

In addition, we hold substantial coal reserves in areas containing Marcellus Shale and other shales. These areas are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If a well is in the path of our mining for coal, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater. Horizontal wells with multiple laterals extending from the well pad may access larger oil and natural gas reserves than a vertical well which could result in higher costs. In future years, the cost associated with purchasing oil and natural gas wells which are in the path of our coal mining may make mining through those wells uneconomical thereby effectively causing a loss of significant portions of our coal reserves.

Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of natural gas and coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and natural gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and natural gas reserves.

We have entered into two significant natural gas joint ventures. These joint ventures restrict our operational and corporate flexibility; actions taken by our joint venture partners may materially impact our financial position and results of operation; and we may not realize the benefits we expect to realize from these joint ventures.

In the second half of 2011, we, through our principal gas operations subsidiary, CNX Gas, entered into joint venture arrangements with Noble Energy, Inc. and with a subsidiary of Hess Corporation, regarding our shale gas assets. We sold a 50% undivided interest in our Marcellus shale oil and natural gas assets to Noble Energy and a 50% undivided interest in our Utica shale acres in Ohio to Hess. The following aspects of these joint ventures could materially impact us:

The development of these properties is subject to the terms of our joint development agreements with these parties and we no longer have the flexibility to control the development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs or, in certain limited circumstances in the case of the Noble Energy joint development agreement, a party elects to exercise a non-consent right with respect to an entire year. If we do not timely meet our financial commitments under the respective joint development agreements, our rights to participate in such joint ventures will be adversely affected and the other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas of mutual interest.

Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by one of our joint venture partners.

Approximately $1.9 billion of consideration that we expect to receive from Noble Energy depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess in which approximately $335 million of consideration that we expect to receive

from Hess is dependent upon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control. The inability or failure of our joint venture partners to pay its portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and natural gas or loss of rights to develop the oil and natural gas properties held by that joint venture.

Noble Energy’s obligation to pay carried costs is currently in effect and will remain in effect unless and until Henry Hub natural gas prices fall below $4.00 per MMbtu for three consecutive months. We cannot predict whether Noble Energy’s obligation to pay carried costs in the future will be suspended based on lower Henry Hub natural gas prices. If such a suspension occurs, we would be required to incur our entire 50 percent share of the drilling and completion costs for new wells during the suspension period and delaying receipt of a portion of the value we expect to receive in the transaction.

Unless Hess consents in its sole discretion, the Hess joint development agreement prohibits any transfer of our interests in the Hess joint venture assets prior to October 21, 2014. After such date, any transfer of interest in the joint venture by us or Hess will be subject to a right of first offer in favor of the other party. These restrictions may preclude transactions which could be beneficial to our shareholders.

Disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

We may also enter into other joint venture arrangements in the future which could pose risks similar to risks described above.

The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.

As of March 31, 2014, our total indebtedness was approximately $3.175 billion of which approximately $1.5 billion was under our 8.00% senior unsecured notes due 2017, $1.25 billion was under our 8.25% senior unsecured notes due 2020, $250 million was under our 6.375% senior notes due 2021, $103 million was under our Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (MEDCO) 5.75% revenue bonds due September 2025, $56 million of capitalized leases due through 2021, and $16 million of miscellaneous debt.

As discussed under -Consolidated Financial Statements-Notes to Unaudited Consolidated Financial Statements-Item 18-Subsequent Events, in April 2014, we commenced a series of transactions intended to reduce our fixed charges and update the covenants contained in the documents governing our indebtedness. We launched a cash tender offer to purchase all of our senior unsecured notes due 2017 and subsequently issued a call notice for any notes left outstanding after the consummation thereof. To fund such tender offer and redemption, on April 16, 2014, we issued $1.6 billion of new 5.875% notes due 2022.

•The degree to which we are leveraged could have important consequences, including, but not limited to:

•increasing our vulnerability to general adverse economic and industry conditions;

•requiring us to dedicate a substantial portion of our cash flow from operations to the payment of interest and principal due under our outstanding debt, which will limit our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;

•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and

•placing us at a competitive disadvantage compared our competitors with lower leverage and better access to capital resources.

Our senior secured credit facilities and the indentures governing our 5.875%, 8.00%, 8.25% and 6.375% senior unsecured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreements and the indentures governing our 5.875%, 8.00%, 8.25% and 6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreements, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, and a maximum senior secured leverage ratio, as defined therein. Our senior secured credit agreements and the indentures governing our 5.875%, 8.00%, 8.25% and 6.375% senior unsecured notes impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have an adverse effect on us.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indentures governing our 5.875%, 8.00%, 8.25% and 6.375% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

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.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition. Additionally, our development and exploration projects require substantial capital expenditures and if we fail to obtain required capital or financing on satisfactory terms, our natural gas reserves may decline.

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well development (primarily drilling), reserve acquisitions, exploratory activity, coal development, corporate items and other alternatives. We also considered our likely sources of capital, including cash generated from operations and borrowings under our credit facilities. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

As part of our strategic determinations, we expect to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves. We cannot assure you that we will have sufficient cash from operations, borrowing capacity under our credit facilities or the ability to raise additional funds in the capital markets. If cash flow generated by our operations or available borrowings under our credit facilities are not sufficient to meet our capital requirements, or we are unable to obtain additional financing, we could be required to curtail the pace of the development of our natural gas properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

ITEM 4. MINE SAFETY DISCLOSURES

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


ITEM 6.	EXHIBITS



10.1			Eighth Amendment to Amended and Restated Receivables Purchase Agreement, dated November 8, 2012, 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 LC Bank.

10.2			Tenth Amendment to Amended and Restated Receivables Purchase Agreement, dated March 28, 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 LC Bank.

10.3			Form of Performance Share Unit Award Agreement (for 2014 awards).

10.4			Form of 5-Year Restricted Stock Unit Award Agreement.

10.5			Form of CONSOL Stock Unit Acknowledgement Letter.

10.6			Form of CONSOL Stock Unit Acknowledgement Letter (Alternate).

10.7			Amended and Restated Employment Agreement between CONSOL Energy Inc. and J. Brett Harvey, dated March 21, 2014, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 26, 2014.

10.8			Change in Control Agreement by and between CONSOL Energy Inc. and David M. Khani.

10.9			Change in Control Agreement by and between CONSOL Energy Inc. and James C. Grech.

10.10			Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Stephen W. Johnson, incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2008 of CNX Gas Corporation (file no. 001-32723) filed on February 17, 2009.

10.11			Executive Compensation Clawback Policy.

10.12			CONSOL Energy Inc. Defined Contribution Restoration Plan.

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, 2014 furnished in XBRL).

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

SIGNATURES

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

Dated: May 6, 2014



	CONSOL ENERGY INC.

	By:		/S/ J. BRETT HARVEY
			J. Brett Harvey
			Chairman of the Board and Chief Executive Officer (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)