CNX Resources Corp - Quarter Report: 2013 June (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 June 30, 2013



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

For the transition period from to

Commission file number: 001-14901

__________________________________________________

CONSOL Energy Inc.

(Exact name of registrant as specified in its charter)



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

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

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

__________________________________________________

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

Yes x No o

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

Yes x No o

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

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

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

Yes o No x

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



Class		Shares outstanding as of July 18, 2013
Common stock, $0.01 par value		228,848,942

TABLE OF CONTENTS

		Page
PART I FINANCIAL INFORMATION

ITEM 1.	Condensed Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2013 and 2012	3
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2013 and 2012	4
	Consolidated Balance Sheets at June 30, 2013 and December 31, 2012	5
	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2013	7
	Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012	8
	Notes to Unaudited Consolidated Financial Statements	9

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

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	88

ITEM 4.	Controls and Procedures	90

PART II OTHER INFORMATION

ITEM 1.	Legal Proceedings	91

ITEM 4.	Mine Safety Disclosures	91

ITEM 6.	Exhibits	91

PART I

FINANCIAL INFORMATION


ITEM 1.	CONDENSED FINANCIAL STATEMENTS

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(Dollars in thousands, except per share data)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013			2012
Sales—Outside	$	1,125,776		$	1,189,293	$	2,351,941		$	2,500,764
Sales—Gas Royalty Interests	17,028			9,533		31,232			21,739
Sales—Purchased Gas	1,406			651		2,764			1,490
Freight—Outside	10,125			49,472		24,186			98,765
Other Income	62,345			205,538		96,197			258,499
Total Revenue and Other Income	1,216,680			1,454,487		2,506,320			2,881,257
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	855,878			856,889		1,788,841			1,760,930
Gas Royalty Interests Costs	13,534			7,124		25,340			17,373
Purchased Gas Costs	1,061			869		2,020			1,386
Freight Expense	10,125			49,472		24,186			98,765
Selling, General and Administrative Expenses	37,123			33,732		70,793			72,731
Depreciation, Depletion and Amortization	159,307			153,824		320,622			309,171
Interest Expense	54,518			56,593		107,896			114,713
Taxes Other Than Income	83,325			84,329		166,112			175,956
Total Costs	1,214,871			1,242,832		2,505,810			2,551,025
Earnings Before Income Taxes	1,809			211,655		510			330,232
Income Taxes	14,622			58,945		15,144			80,326
Net (Loss) Income	(12,813		)	152,710		(14,634		)	249,906
Add: Net Loss Attributable to Noncontrolling Interest	287			29		544			29
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	152,739	$	(14,090	)	$	249,935
Earnings Per Share:
Basic	$	(0.05	)	$	0.67	$	(0.06	)	$	1.10
Dilutive	$	(0.05	)	$	0.67	$	(0.06	)	$	1.09
Weighted Average Number of Common Shares Outstanding:
Basic	228,721,980			227,548,394		228,520,886			227,408,832
Dilutive	228,721,980			229,252,185		228,520,886			229,122,594
Dividends Paid Per Share	$	0.125		$	0.125	$	0.125		$	0.250

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(Dollars in thousands)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net (Loss) Income	$	(12,813	)	$	152,710		$	(14,634	)	$	249,906
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($26,489), ($4,570), ($54,739), ($40,467))	42,904			7,586			88,661			67,159
Net Increase in the Value of Cash Flow Hedges (Net of tax: ($31,466), ($6,869), ($17,500), ($55,877))	45,749			10,663			27,154			86,739
Reclassification of Cash Flow Hedges from OCI to Earnings (Net of tax: $10,542, $36,697, $22,526, $68,077)	(9,528		)	(57,847		)	(32,241		)	(105,788		)

Other Comprehensive Income (Loss)	79,125			(39,598		)	83,574			48,110

Comprehensive Income	66,312			113,112			68,940			298,016

Add: Comprehensive Loss Attributable to Noncontrolling Interest	287			29			544			29

Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders	$	66,599		$	113,141		$	69,484		$	298,045

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	(Unaudited)
	June 30, 2013		December 31, 2012
ASSETS
Current Assets:
Cash and Cash Equivalents	$	71,938	$	21,878
Accounts and Notes Receivable:
Trade	347,367		428,328
Notes Receivables	350,977		318,387
Other Receivables	151,269		131,131
Accounts Receivable - Securitized	40,719		37,846
Inventories	227,994		247,766
Deferred Income Taxes	143,004		148,104
Recoverable Income Taxes	1,930		—
Restricted Cash	—		48,294
Prepaid Expenses	137,643		157,360
Total Current Assets	1,472,841		1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	16,194,251		15,545,204
Less—Accumulated Depreciation, Depletion and Amortization	5,770,506		5,354,237
Total Property, Plant and Equipment—Net	10,423,745		10,190,967
Other Assets:
Deferred Income Taxes	388,703		444,585
Restricted Cash	—		20,379
Investment in Affiliates	256,097		222,830
Notes Receivable	1,512		25,977
Other	210,030		227,077
Total Other Assets	856,342		940,848
TOTAL ASSETS	$	12,752,928	$	12,670,909

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)



	(Unaudited)
	June 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	461,415		$	507,982
Current Portion of Long-Term Debt	13,422			13,485
Short-Term Notes Payable	173,000			25,073
Accrued Income Taxes	—			34,219
Borrowings Under Securitization Facility	40,719			37,846
Other Accrued Liabilities	798,645			768,494
Total Current Liabilities	1,487,201			1,387,099
Long-Term Debt:
Long-Term Debt	3,124,000			3,124,473
Capital Lease Obligations	47,750			50,113
Total Long-Term Debt	3,171,750			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	2,820,186			2,832,401
Pneumoconiosis Benefits	177,146			174,781
Mine Closing	459,392			446,727
Gas Well Closing	193,946			148,928
Workers’ Compensation	155,518			155,648
Salary Retirement	109,691			218,004
Reclamation	50,051			47,965
Other	102,987			131,025
Total Deferred Credits and Other Liabilities	4,068,917			4,155,479
TOTAL LIABILITIES	8,727,868			8,717,164
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,834,765 Issued and 228,800,010 Outstanding at June 30, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012	2,291			2,284
Capital in Excess of Par Value	2,336,417			2,296,908
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	—			—
Retained Earnings	2,351,320			2,402,551
Accumulated Other Comprehensive Loss	(663,768		)	(747,342		)
Common Stock in Treasury, at Cost—34,755 Shares at June 30, 2013 and 34,755 Shares at December 31, 2012	(609		)	(609		)
Total CONSOL Energy Inc. Stockholders’ Equity	4,025,651			3,953,792
Noncontrolling Interest	(591		)	(47		)
TOTAL EQUITY	4,025,060			3,953,745
TOTAL LIABILITIES AND EQUITY	$	12,752,928		$	12,670,909

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)			Common Stock in Treasury			Total CONSOL Energy Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
December 31, 2012	$	2,284	$	2,296,908		$	2,402,551		$	(747,342	)	$	(609	)	$	3,953,792		$	(47	)	$	3,953,745
(Unaudited)
Net Loss	—		—			(14,090		)	—			—			(14,090		)	(544		)	(14,634		)
Other Comprehensive Income	—		—			—			83,574			—			83,574			—			83,574
Comprehensive (Loss) Income	—		—			(14,090		)	83,574			—			69,484			(544		)	68,940
Issuance of Common Stock	7		2,490			—			—			—			2,497			—			2,497
Treasury Stock Activity	—		—			(8,540		)	—			—			(8,540		)	—			(8,540		)
Tax Cost From Stock-Based Compensation	—		(2,222		)	—			—			—			(2,222		)	—			(2,222		)
Amortization of Stock-Based Compensation Awards	—		39,241			—			—			—			39,241			—			39,241
Dividends ($0.125 per share)	—		—			(28,601		)	—			—			(28,601		)	—			(28,601		)
Balance at June 30, 2013	$	2,291	$	2,336,417		$	2,351,320		$	(663,768	)	$	(609	)	$	4,025,651		$	(591	)	$	4,025,060

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

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)



	Six Months Ended
	June 30,
	2013			2012
Operating Activities:
Net (Loss) Income	$	(14,634	)	$	249,906
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization	320,622			309,171
Stock-Based Compensation	39,241			26,935
Gain on Sale of Assets	(32,958		)	(189,981		)
Amortization of Mineral Leases	761			3,631
Deferred Income Taxes	6,998			30,625
Equity in Earnings of Affiliates	(16,667		)	(15,103		)
Changes in Operating Assets:
Accounts and Notes Receivable	25,360			40,034
Inventories	19,772			(46,726		)
Prepaid Expenses	24,433			19,709
Changes in Other Assets	24,512			10,604
Changes in Operating Liabilities:
Accounts Payable	(13,470		)	(41,266		)
Other Operating Liabilities	(6,019		)	(65,693		)
Changes in Other Liabilities	2,807			23,456
Other	12,636			12,647
Net Cash Provided by Operating Activities	393,394			367,949
Investing Activities:
Capital Expenditures	(758,000		)	(714,399		)
Change in Restricted Cash	68,673			—
Proceeds from Sales of Assets	240,801			252,229
Net Investments In Equity Affiliates	(16,600		)	(21,839		)
Net Cash Used in Investing Activities	(465,126		)	(484,009		)
Financing Activities:
Proceeds from Short-Term Borrowings	173,000			—
Payments on Miscellaneous Borrowings	(30,162		)	(4,662		)
Proceeds from Securitization Facility	2,873			—
Tax Benefit from Stock-Based Compensation	2,185			1,608
Dividends Paid	(28,601		)	(56,833		)
Issuance of Common Stock	2,497			457
Issuance of Treasury Stock	—			109
Debt Issuance and Financing Fees	—			(148		)
Net Cash Provided by (Used In) Financing Activities	121,792			(59,469		)
Net Increase (Decrease) in Cash and Cash Equivalents	50,060			(175,529		)
Cash and Cash Equivalents at Beginning of Period	21,878			375,736
Cash and Cash Equivalents at End of Period	$	71,938		$	200,207

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

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

NOTE 1—BASIS OF PRESENTATION:

The accompanying Unaudited Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2012 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, 2012 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, 2012, with no effect on previously reported net income or stockholders' equity.

Basic earnings per share are computed by dividing net (loss) income 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 share 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 share 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 June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Anti-Dilutive Options	4,845,029	2,421,923	4,845,029	2,418,983
Anti-Dilutive Restricted Stock Units	1,383,908	2,642	1,383,908	13,552
Anti-Dilutive Performance Share Units	83,356	91,340	83,356	91,340
Anti-Dilutive Performance Share Options	602,101	501,744	602,101	501,744
	6,914,394	3,017,649	6,914,394	3,025,619

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Options	160,119	39,418	245,113	51,134
Restricted Stock Units	89,632	64,589	568,141	522,607
Performance Share Units	—	—	159,228	229,730
	249,751	104,007	972,482	803,471

The weighted average exercise price per share of the options exercised during the three months ended June 30, 2013 and 2012 was $9.90 and $10.26, respectively. The weighted average exercise price per share of the options exercised during the six months ended June 30, 2013 and 2012 was $10.16 and $11.07, respectively.

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2013			2012		2013			2012
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	152,739	$	(14,090	)	$	249,935
Weighted average shares of common stock outstanding:
Basic	228,721,980			227,548,394		228,520,886			227,408,832
Effect of stock-based compensation awards	—			1,703,791		—			1,713,762
Dilutive	228,721,980			229,252,185		228,520,886			229,122,594
Earnings per share:
Basic	$	(0.05	)	$	0.67	$	(0.06	)	$	1.10
Dilutive	$	(0.05	)	$	0.67	$	(0.06	)	$	1.09

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, 2012	$	76,761		$	(824,103	)	$	(747,342	)
Other comprehensive income before reclassifications	27,154			48,766			75,920
Amounts reclassified from accumulated other comprehensive income	(32,241		)	39,895			7,654
New current period other comprehensive income	(5,087		)	88,661			83,574
Balance at June 30, 2013	$	71,674		$	(735,442	)	$	(663,768	)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Derivative Instruments (Note 12)
Natural gas price swaps	$	(20,070	)	$	(94,544	)	$	(54,767	)	$	(173,865	)
Tax benefit	10,542			36,697			22,526			68,077
Net of tax	$	(9,528	)	$	(57,847	)	$	(32,241	)	$	(105,788	)
Actuarially Determined Long-Term Liability Adjustments*(Note 3 and Note 4)
Amortization of prior service costs	$	(8,211	)	$	(13,915	)	$	(16,423	)	$	(26,021	)
Recognized net actuarial loss	23,559			26,072			48,747			53,077
Settlement loss	5,087			—			32,202			—
Total	20,435			12,157			64,526			27,056
Tax expense	(7,800		)	(4,571		)	(24,631		)	(10,173		)
Net of tax	$	12,635		$	7,586		$	39,895		$	16,883

*Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the three months and six months ended June 30, 2013 and June 30, 2012.

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

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

In May 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Robinson Run Mine. Cash proceeds for the sale were $68,337. A loss of $236 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.

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

On 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 forgoes the bonus. Our joint venture partner, Noble Energy Inc., has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs during the three months ended June 30, 2013.

In March 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Shoemaker Mine. Cash proceeds for the sale were $63,839. A loss of $279 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.

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.

On December 21, 2012, CONSOL Energy completed the disposition of its non-producing Ram River & Scurry Ram assets in Western Canada which consisted of 36 thousand acres of coal lands. In December 2012, cash proceeds of $51,869, of which $48,294 was restricted, were received related to this transaction. These proceeds were net of $637 in transaction fees. The restrictions on the cash were removed during the three months ended March 31, 2013 and are reflected as a Change in Restricted Cash in the Investing section of the Consolidated Statement of Cash Flows. Additionally, a note receivable was recognized in 2012 related to the two additional cash payments to be received in June 2013 and June 2014. One payment of $25,500 was received in June 2013. A note receivable of $24,500 is included in Accounts and Notes Receivables - Notes Receivables in the Consolidated Balance Sheet at June 30, 2013. The second payment is due June 2014. The gain on the transaction was $89,943 and was included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On June 29, 2012, CONSOL Energy completed the disposition of its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for cash proceeds of $169,500. The assets consisted of CONSOL Energy's 50% interest in Youngs Creek Mining Company LLC, CONSOL Energy's 50% interest in CX Ranch and related properties in and around Sheridan, Wyoming. The gain on the transaction was $150,677 and is included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal.

On April 4, 2012, CONSOL Energy completed the disposition of its non-producing Elk Creek property in southern West Virginia, which consisted of 20 thousand acres of coal lands and surface rights, for proceeds of $26,000. The gain on the transaction was $11,235 and is included in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012.

On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property in Illinois, which consisted of 4.3 thousand acres of coal lands and surface rights, for proceeds of $13,023. The gain on the transaction was $11,261 and is included in Other Income in the Consolidated Statements of Income for the year ended December 31, 2012.

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

Components of net periodic costs (benefits) for the three and six months ended June 30 are as follows:



	Pension Benefits												Other Postretirement Benefits
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	5,581		$	4,850		$	11,287		$	10,003		$	4,849		$	4,566		$	9,698		$	9,766
Interest cost	8,909			9,415			17,752			18,793			29,619			32,795			59,237			68,322
Expected return on plan assets	(12,711		)	(11,452		)	(24,855		)	(23,079		)	—			—			—			—
Amortization of prior service cost (credits)	(407		)	(407		)	(815		)	(815		)	(7,804		)	(13,410		)	(15,608		)	(25,009		)
Recognized net actuarial loss	10,547			11,654			22,722			23,917			17,595			20,020			35,190			40,365
Settlement loss	5,087			—			32,202			—			—			—			—			—
Net periodic benefit cost	$	17,006		$	14,060		$	58,293		$	28,819		$	44,259		$	43,971		$	88,517		$	93,444

For the six months ended June 30, 2013, $34,376 was paid to the pension trust for pension benefits from operating cash flows. CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $50,000 to the pension trust in 2013. Net periodic benefit costs are allocated to Costs of Goods Sold and Other Operating Charges and Selling, General and Administrative Expenses 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 six months ended June 30, 2013. Accordingly, CONSOL Energy recognized expense of $5,087 and $32,202 for the three and six months ended June 30, 2013, respectively, in Costs of Goods Sold and Other Operating Charges 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 June 30 and March 31, 2013. The June 30, 2013 remeasurement resulted in a change to the discount rate to 4.84% from 4.12% at March 31, 2013. The June remeasurement reduced the pension liability by $48,957. The June settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $33,414 in other comprehensive income, net of $20,630 in deferred taxes. The March 31, 2013 remeasurement resulted in a change to the discount rate to 4.12% from 4.00% at December 31, 2012. The March remeasurement reduced the pension liability by $29,916. The March settlement and corresponding remeasurement of the pension plan resulted in an adjustment of $35,261 in other comprehensive income, net of $21,770 in deferred taxes. Currently, the settlement and remeasurement of the pension plan will result in a $10,960 reduction to pension expense compared to what was originally expected to be recognized for the remaining six months of 2013. It is reasonably possible that CONSOL Energy will incur additional settlement charges in 2013, which would require the pension plan to be remeasured using updated assumptions.

CONSOL Energy does not expect to contribute to the other postretirement benefit plan in 2013. We intend to pay benefit claims as they become due. For the six months ended June 30, 2013, $83,106 of other postretirement 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 and six months ended June 30 are as follows:



	CWP												Workers' Compensation
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	2,135		$	1,928		$	4,270		$	3,856		$	3,533		$	3,634		$	7,066		$	7,268
Interest cost	1,808			1,991			3,616			3,982			1,655			1,778			3,310			3,556
Amortization of actuarial gain	(4,212		)	(4,933		)	(8,425		)	(9,867		)	(699		)	(986		)	(1,398		)	(1,972		)
State administrative fees and insurance bond premiums	—			—			—			—			1,345			1,635			3,004			3,545
Legal and administrative costs	—			—			—			—			591			648			1,182			1,296
Net periodic (benefit) cost	$	(269	)	$	(1,014	)	$	(539	)	$	(2,029	)	$	6,425		$	6,709		$	13,164		$	13,693

CONSOL Energy does not expect to contribute to the CWP plan in 2013. We intend to pay benefit claims as they become due. For the six months ended June 30, 2013, $5,372 of CWP benefit claims have been paid.

CONSOL Energy does not expect to contribute to the workers’ compensation plan in 2013. We intend to pay benefit claims as they become due. For the six months ended June 30, 2013, $14,946 of workers’ compensation benefits, state administrative fees and surety bond premiums have been paid.

NOTE 5—INCOME TAXES:

The effective tax rate for the 2013 and 2012 six-month periods was 2,969.4% and 24.3%, respectively.

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

The rate for the six months ended June 30, 2012 differs from the U.S. federal statutory rate of 35% primarily due to a $39,275 benefit recorded for excess depletion.

The total amounts of uncertain tax positions at June 30, 2013 and 2012 were $22,770 and $25,570, respectively. If these uncertain tax positions were recognized, approximately $2,071 and $3,891, respectively, would affect CONSOL Energy’s effective tax rate. There were no additions to the liability for unrecognized tax benefits during the six months ended June 30, 2013 and 2012.

CONSOL Energy recognizes interest accrued related to uncertain tax positions in its interest expense. As of June 30, 2013 and 2012, the Company reported an accrued interest liability relating to uncertain tax positions of $5,505 and $6,429, respectively. The accrued interest liability includes $675 and $1,055 of interest expense that is reflected in the Company’s Consolidated Statements of Income for the six months ended June 30, 2013 and 2012, respectively.

CONSOL Energy recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of June 30, 2013 and 2012, CONSOL Energy had no accrued liability for tax penalties.

NOTE 6—INVENTORIES:

Inventory components consist of the following:



	June 30, 2013		December 31, 2012
Coal	$	52,406	$	78,825
Merchandise for resale	36,476		35,363
Supplies	139,112		133,578
Total Inventories	$	227,994	$	247,766

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 $18,734 and $19,700 at June 30, 2013 and December 31, 2012, 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 $200,000. The facility also allows for the issuance of letters of credit against the $200,000 capacity. At June 30, 2013, there were letters of credit outstanding against the facility of $159,281. CONSOL Energy management believes that these guarantees 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, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $440 and $913 for three and six months ended June 30, 2013, respectively. Costs associated with the receivables facility totaled $437 and $856 for three and six months ended June 30, 2012, respectively. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2017 with the underlying liquidity agreement renewing annually each March.

At June 30, 2013 and December 31, 2012, eligible accounts receivable totaled $181,000 and $200,000, respectively. There was no subordinated retained interest at June 30, 2013 and at December 31, 2012. There were $40,719 borrowings under the Securitization Facility recorded on the Consolidated Balance Sheet as of June 30, 2013 and $37,846 at December 31, 2012. The accounts receivable securitization program increased $2,873 in the six months ended June 30, 2013 and there was no change in the six months ended June 30, 2012. The increase is reflected in the Net Cash Provided by (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:



	June 30, 2013		December 31, 2012
Coal and other plant and equipment	$	6,086,734	$	6,030,620
Intangible drilling cost	1,721,384		1,550,297
Proven gas properties	1,597,626		1,596,838
Coal properties and surface lands	1,455,541		1,346,151
Unproven gas properties	1,371,532		1,266,017
Gas gathering equipment	1,034,927		1,006,882
Airshafts	727,674		706,388
Mine development	583,494		537,939
Leased coal lands	529,700		529,758
Gas wells and related equipment	542,284		492,367
Coal advance mining royalties	396,034		391,501
Other gas assets	125,194		82,217
Gas advance royalties	22,127		8,229
Total Property Plant and Equipment	16,194,251		15,545,204
Less: Accumulated DD&A	5,770,506		5,354,237
Total Net PP&E	$	10,423,745	$	10,190,967

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.

On October 21, 2011, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which were net of $5,719 transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The aggregate amount of the drilling carry can be adjusted downward under provisions of the joint venture agreements in certain events. The net gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. CONSOL Energy and Hess have agreed to focus their development efforts on six core counties in southeastern Ohio, in which the joint venture holds approximately 73,000 mostly fee acres. To this end, the parties have agreed to pursue the sale of approximately 63,000 acres outside of the focus areas. In addition, as previously announced, based on title work performed by Hess as part of the title defect process, we believe that there are chain of title issues with respect to approximately 39,000 of the joint venture acres representing approximately $153,000 of carry, most of which likely cannot be cured. These acres, together with another 26,000 acres of allegedly defective acres will be reassigned to CONSOL Energy. CONSOL Energy may elect to cure the alleged defects related to these acres and develop them, or sell the acres for its own account. After taking into account the reassignment of approximately 65,000 acres, the parties have agreed that the total carry remaining after these adjustments is $335,000. The loss of these Utica Shale acres itself will not have a material impact on the Company's financial statements.

On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. In September 2011, cash proceeds of $485,464 were received related to this transaction, which were net of $34,998 transaction fees. Additionally, a note receivable was recognized related to the two additional cash payments to be received on the first and second anniversary of the transaction closing date. The discounted notes receivable of $311,754 and $296,344 were recorded in Accounts and Notes Receivables-Notes Receivable and Other Assets-Notes Receivable, respectively. In September 2012, cash proceeds of $327,964 were received related to the first anniversary note receivable. During December 2011, an additional receivable of $16,703 and a payable of $980 were recorded for closing adjustments and were included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. Adjusted cash proceeds of $15,598 related to the additional receivable were received in April 2012. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. As part of the transaction, CNX

Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub natural gas prices are below $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry is currently suspended and will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble's carried cost obligation. The aggregate amount of the drilling carry may also be adjusted downward under provisions of the joint venture agreements in certain events.

Under our joint venture agreement with Noble, Noble had the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. CONSOL Energy then can review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party can submit the defect to an arbitrator for resolution. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase. Noble Energy has submitted a final title defect notice to CONSOL Energy. Based on our review of the title defect notice, Noble has asserted title defects with respect to approximately 75,000 gross deal acres, having a carry value of approximately $481,000, which have not yet been addressed. We are working closely with Noble to address these alleged defects and we believe that we will resolve most of those defects favorably to CONSOL Energy. To date, we have conceded defects which have an aggregate value of approximately $57,000 in excess of the applicable deductibles. The impact of these conceded defects was $2,470 and $8,780 of expense for the three and six months ended June 30, 2013 and is included in Cost of Goods Sold and Other Charges in the Consolidated Statement of Income.

The following table provides information about our industry participation agreements as of June 30, 2013:



Shale Play	Industry Participation Agreement Partner	Industry Participation Agreement Date	Drilling Carries Remaining*
Marcellus	Noble Energy, Inc.	September 30, 2011	$	2,034,785
Utica	Hess Ohio Developments, LLC	October 21, 2011	$	279,248

*See above for a description of the impact on the drilling carries of title defects that have been asserted by Noble Energy.

NOTE 9—SHORT-TERM NOTES PAYABLE:

CONSOL Energy's $1,500,000 Senior Secured Credit Agreement expires April 12, 2016. 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 $1,500,000 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 2.50 to 1.00, measured quarterly. The interest coverage ratio was 3.44 to 1.00 at June 30, 2013. The facility includes a maximum leverage ratio covenant of no more than 4.50 to 1.00, measured quarterly. The leverage ratio was 3.65 to 1.00 at June 30, 2013. 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 0.12 to 1.00 at June 30, 2013. 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 June 30, 2013 and December 31, 2012, the $1,500,000 facility had no borrowings outstanding and $100,292 of letters of credit outstanding, leaving $1,399,708 of capacity available for borrowings and the issuance of letters of credit.

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 1.20 to 1.00 at June 30, 2013. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 36.85 to 1.00 at June 30, 2013. At June 30, 2013, the $1,000,000 facility had $173,000 borrowings outstanding and $70,051 of letters of credit outstanding, leaving $756,949 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the $1,000,000 facility had no borrowings outstanding and $70,203 of letters of credit outstanding, leaving $929,797 of capacity available for borrowings and the issuance of letters of credit. The average interest rate for the three months and six months ended June 30, 2013 was 1.69% and 1.76%, respectively. Accrued interest of $62 and $29 is included in Other Accrued Liabilities in the Consolidated Balance Sheet at June 30, 2013 and December 31, 2012, respectively.

CONSOL Energy entered into an interim funding arrangement for longwall shields. At December 31, 2012, CONSOL

Energy had a note payable of $25,073 related to this funding arrangement. The interim funding arrangement bore a weighted average interest rate of 2.46% as of December 31, 2012. There were no interim funding agreements outstanding at June 30, 2013.

NOTE 10—LONG-TERM DEBT:



	June 30, 2013		December 31, 2012
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 (7.43% weighted average interest rate for June 30, 2013 and December 31, 2012)	20,394		20,394
Other long-term notes maturing at various dates through 2031 (total value of $6,612 and $7,300 less unamortized discount of $1,286 and $1,542 at June 30, 2013 and December 31, 2012, respectively).	5,326		5,758
	3,128,585		3,129,017
Less amounts due in one year *	4,585		4,544
Long-Term Debt	$	3,124,000	$	3,124,473

* Excludes current portion of Capital Lease Obligations of $8,837 and $8,941 at June 30, 2013 and December 31, 2012, respectively.

Accrued interest related to Long-Term Debt of $63,269 and $63,363 was included in Other Accrued Liabilities in the Consolidated Balance Sheets at June 30, 2013 and December 31, 2012, respectively.

NOTE 11—COMMITMENTS AND CONTINGENCIES:

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 $792,000.

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

American Electric Corp: On August 8, 2011, the United States Environmental Protection Agency, Region IV, sent Consolidation Coal Company a General Notice and Offer to Negotiate regarding the Ellis Road/American Electric Corp. Superfund Site in Jacksonville, Florida. The General Notice was sent to approximately 180 former customers of American Electric Corp. CONSOL Energy has confirmed that it did business with American Electric Corp. in 1983 and 1984. The General Notice indicated that the Environmental Protection Agency (EPA) has determined that polychlorinated biphenyls (PCBs) and other contaminants in the soils and sediments at and near the site require a removal action. The Offer to Negotiate invited the potentially responsible parties (PRPs) to enter into an Administrative Settlement Agreement and Order on Consent (AOC) to provide for conducting the removal action under the EPA oversight and to reimburse the EPA for its past costs, in the amount of $384 and for its future costs. CONSOL Energy responded to the EPA indicating its willingness to participate in such negotiations, and CONSOL Energy is participating in a group of potentially responsible parties to conduct the removal action. The AOC was signed on July 20, 2012, and as a result, the EPA granted the performing parties a $408 orphan share credit, which will offset the EPA's past costs. The actual scope of the work has yet to be determined, but the current estimate of the total costs of the removal action is in the range of $2,000 to $5,400, with CONSOL Energy's share of such costs at approximately 8%. In 2011, CONSOL Energy established an initial accrual based on its allocated share of the costs among the viable former customers of American Electric Corp. During the year ended December 31, 2012, CONSOL Energy funded $250 to an independent trust established for the remediation, which is 50% of CONSOL Energy's allocated share of the trust fund. The liability is immaterial to the overall financial position of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the EPA that it is a potentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), with respect to the Ward Transformer site in Wake County, North Carolina. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties and in September 2008, the EPA notified CONSOL Energy and 60 other companies that they are PRPs for these additional areas. The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA's past and future cost, is approximately $65,000. The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $11,000. CONSOL Energy recognized no expense in Cost of Goods Sold and Other charges in the three or six months ended June 30, 2013 and 2012, respectively. Also, CONSOL Energy has provided funding to an independent trust established for this remediation. CONSOL Energy funded $430 in the six months ended June 30, 2013. No funding was made in the six months ended June 30, 2012. As of June 30, 2013, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy's portion of recoveries from settled claims is $4,369. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at June 30, 2013 is $2,762.

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 is included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestos cases have not been material.

Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company's underground longwall mining activities at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently breached the dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resource damages totaling $58,000. In October 2008, the Common Pleas Court ruled that natural resource damages were not recoverable and referred the Commonwealth's claim to the Pennsylvania Department of Environmental Protection (DEP). In February 2010, the DEP issued

an interim report, concluding that the alleged damage was subsidence related. The DEP estimated the cost of repair to be approximately $20,000. The Company appealed the DEP's findings to the Pennsylvania Environmental Hearing Board (PEHB). In April 2013, this Company and the Commonwealth entered into a Settlement Agreement and Release settling all of the Commonwealth's claims regarding the Dam and the Lake. The Settlement provides in part for the payment to the Commonwealth of $36,000 for use to rebuild the Dam and restore the Lake with $13,728 of the settlement amount credited to lease bonus and royalty payments on the Commonwealth's Marcellus gas interests within the Park, subject to the Company's agreement to extract the gas from surface facilities located outside of the boundaries of the Park. The Settlement also provides in part for the conveyance by the Company to the Commonwealth of eight surface parcels containing approximately 506 acres of land adjoining the Park after the Parcels are no longer needed for the Company's operations and the conveyance by the Commonwealth to the Company certain coal and mining rights in an area of the Bailey Mine where a mining permit application is currently pending.

South Carolina Electric & Gas Company Arbitration: In April, 2009, South Carolina Electric & Gas Company (SCE&G), a public utility, filed an arbitration complaint, against CONSOL of Kentucky Inc. and CONSOL Energy Sales Company, both wholly owned subsidiaries of CONSOL Energy, seeking $36,000 in damages. SCE&G claimed it suffered those damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. CONSOL Energy counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement, alleging that SCE&G had agreed that shortfalls could be made up in 2009. A four day hearing on the claims commenced on April 30, 2012. On December 21, 2012, the Arbitration Panel awarded SCE&G $9,735, plus interest at 8.75% from January 9, 2011, and attorney fees. The Award is against CONSOL of Kentucky only. The Panel is currently considering SCE&G's attorney fee claim of $1,873, which has been vigorously opposed by CONSOL Energy. 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 Sheet.

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 conflicting claimant, 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. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty. The Magistrate Judge recommended against the dismissal of certain other claims. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. 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. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013, and the District Judge has scheduled argument on the Objections on September 12, 2013. Discovery is proceeding in this litigation. 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 Sheet.

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 Magistrate Judge issued a Report and Recommendation recommending dismissing some claims and allowing others to proceed. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. 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. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013, and the District Judge has scheduled argument on the Objections on September 12, 2013. Discovery is proceeding in this litigation. 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 Sheet.

CNX Gas Shareholders Litigation: CONSOL Energy was named as a defendant in four putative class actions brought by alleged shareholders of CNX Gas Corporation challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the two cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL). (A third case filed in Delaware was voluntarily dismissed by the plaintiff in 2010.) All four actions generally allege that CONSOL Energy breached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 per share price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, the actions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys' fees and expenses. Following a mediation, the parties to the Delaware litigation have agreed in principle to a settlement and release of all of the claims of the plaintiff class (as defined in a January 20, 2011 order of certification) in exchange for defendants' agreement to establish a settlement fund in the amount of $42,730 for distribution to class members, of which CONSOL Energy is responsible for $20,200. On May 8, 2013, the parties executed and filed with the Court a Stipulation and Agreement of Compromise and Settlement. A Settlement Hearing has been scheduled by the Court on August 23, 2013.

The following lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly no accrual has been recognized.

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: On March 22, 2012, the Company was served with four complaints filed on May 31, 2011 by four individuals against Consolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, subsidiaries of CONSOL Energy, as well as CONSOL Energy itself in the Circuit Court of Russell County, Virginia. The complaints seek damages and injunctive relief in connection with the deposit of water from mining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits allege damage to coal and coalbed methane and seek recovery in tort, contract and assumpsit (quasi-contract). The cases were removed to federal court, motions to dismiss were filed by CCC, and then were voluntarily dismissed by the plaintiffs. On January 30, 2013, the four plaintiffs filed a single consolidated complaint against the same defendants in the United States District Court for the Western District of Virginia, alleging the same damage and theories of recovery for storage of water in the mine voids ostensibly underlying their property. The suit seeks damages ranging from $4,000 to $8,000 plus punitive damages. Service was effected on April 1, 2013 by waiver. A Motion to Dismiss Plaintiffs' Complaint and, in the Alternative, Motion for More Definitive Statement was filed by the defendants on May 31, 2013. Plaintiffs' Response in opposition to the Motion to Dismiss was filed on June 20, 2013, and the defendants on July 1, 2013, filed their Reply to the Response. Without first seeking the required leave of Court, plaintiffs filed a Sur Reply brief on July 8, 2013, for the first time arguing the interpretation of the Virginia Mine Void Statute urged by defendants was unconstitutional. The defendants have moved to strike the Sur Reply and have asked the Court to deny plaintiffs' after-the-fact Motion for Leave to file the Sur Reply brief. CONSOL Energy intends to vigorously defend the suit.

Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court. The named plaintiff is Earl D. Hall. The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy. The complaint alleges more than 1,000 similarly situated lessors. The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying

royalties on oil production. The complaint also alleges that royalty statements were false and misleading. The complaint seeks damages, interest and an accounting on a well-by-well basis. The case has been inactive since December 2011. 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.

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 plaintiffs are seeking to appeal that dismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summary judgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled for CNX Gas Company and CONSOL Energy, holding that the “roof/rider” coal is included in the Pittsburgh 8 coal seam. The plaintiffs have indicated that they intend to appeal that decision. A trial on the issue of whether a drilling that deviates from the coal seam results in damage to the gas owner is now scheduled for October 21, 2013. CNX Gas Company and CONSOL Energy believe this lawsuit to be without merit and intend to vigorously defend it. Consequently, we have not recognized any liability related to these actions.

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 amended its complaint twice to include allegations that CONSOL Energy and Dominion Resources are liable for their subsidiaries' actions and that Rowland's title has been slandered. Motions to dismiss have been denied, discovery is proceeding but stayed pending mediation. Initial mediation efforts have been unsuccessful but settlement discussions are continuing. 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.

Majorsville Storage Field Declaratory Judgment: On March 3, 2011, an attorney sent a letter to CNX Gas Company regarding certain leases that CNX Gas Company obtained from Columbia Gas in Greene County, Pennsylvania involving the Majorsville Storage Field. The letter was written on behalf of three lessors alleging that the leases totaling 525 acres are invalid, and had expired by their terms. The plaintiffs' theory is that the rights of storage and production are severable under the leases. Ignoring the fact that the leases have been used for gas storage, they claim that since there has been no production or development of production, the right to produce gas expired at the end of the primary terms. On June 16, 2011, in the Court of Common Pleas of Greene County, Pennsylvania, the Company filed a declaratory judgment action, seeking to have a court confirm the validity of the leases. Discovery is proceeding in this litigation. We believe that we will prevail in this litigation based on the language of the leases and the current status of the law. Consequently, we have not recognized any liability related to these actions.

The following lawsuit and claims include those for which a loss is remote and accordingly, no accrual has been recognized, although if a non-favorable verdict were received the impact could be material.

Comer Litigation: In 2005, plaintiffs Ned Comer and others filed a purported class action lawsuit in the U.S. District Court for the Southern District of Mississippi against a number of companies in energy, fossil fuels and chemical industries, including CONSOL Energy styled, Comer, et al. v. Murphy Oil, et al. (Comer I). The plaintiffs, residents and owners of property along the Mississippi Gulf coast, alleged that the defendants caused the emission of greenhouse gases that contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to destroy the plaintiffs' property. The District Court dismissed the case and the plaintiffs appealed. The Circuit Court panel reversed and the defendants sought a rehearing before the entire court. A rehearing before the entire court was granted, which had the effect of vacating the panel's reversal, but before the case could be heard on the merits, a number of judges recused themselves and there was no longer a quorum. As a result, the District Court's dismissal was effectively reinstated. The plaintiffs asked the U.S. Supreme Court to require the Circuit Court to address the merits of their appeal. On January 11, 2011, the Supreme Court denied that request. Although that should have resulted in the dismissal being final, the plaintiffs filed a lawsuit on May 27, 2011, in the same jurisdiction against essentially the same defendants making nearly identical allegations as in the original lawsuit (Comer II). The trial court dismissed this case, and the dismissal was appealed. On May 14, 2013, a panel of the U.S. Court of Appeals for

the Fifth Circuit affirmed, holding res judicata arising from Comer I bars the plaintiffs' claims in Comer II. On June 5, 2013, the Fifth Circuit issued its mandate. If they wish to do so, plaintiffs have until August 12, 2013, to file a certiorari petition with the Supreme Court of the United States.

At June 30, 2013, 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	$	190,157	$	95,847	$	94,310	$	—	$	—
Environmental	56,294		54,566		1,728		—		—
Other	83,246		31,015		52,231		—		—
Total Letters of Credit	329,697		181,428		148,269		—		—
Surety Bonds:
Employee-Related	204,884		194,884		10,000		—		—
Environmental	533,725		527,938		5,787		—		—
Other	30,946		30,935		10		—		1
Total Surety Bonds	769,555		753,757		15,797		—		1
Total Commitments	$	1,099,252	$	935,185	$	164,066	$	—	$	1

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state and federal workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Coal and Gas financial guarantees have primarily been provided to support various sales contracts. Other guarantees have also been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business.

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 Sheet. As of June 30, 2013, the purchase obligations for each of the next five years and beyond were as follows:



Obligations Due	Amount
Less than 1 year	$	258,380
1 - 3 years	164,240
3 - 5 years	131,751
More than 5 years	405,934
Total Purchase Obligations	$	960,305

Costs related to these purchase obligations include:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Major equipment purchases	$	15,116	$	31,989	$	48,542	$	45,175
Firm transportation expense	31,017		15,822		59,542		30,867
Gas drilling obligations	25,904		28,517		54,768		58,093
Other	—		129		—		427
Total costs related to purchase obligations	$	72,037	$	76,457	$	162,852	$	134,562

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) are based on intra-bank 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 Outside 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 requires 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.

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 contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodity. As of June 30, 2013, the total notional amount of the Company’s outstanding natural gas swap contracts was 197.7 billion cubic feet. These swap contracts 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. During the next twelve months, $49,614 of unrealized gain is expected to be reclassified from Other Comprehensive Income on the Consolidated Balance Sheets and into Outside Sales on the Consolidated Statements of Income, as a result of the gross settlements of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gross fair value at June 30, 2013 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $120,973 and a liability of $4,854. The total asset is comprised of $82,061 and $38,912 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $860 and $3,994 which were included in Other Accrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.

The gross fair value at December 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, was an asset of $135,969 and a liability of $7,024. The total asset is comprised of $80,057 and $55,912 which were included in Prepaid Expense and Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $970 and $6,054 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 were as follows:



	For the Three Months Ended June 30,
	2013			2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	35,453		$	179,915
Gain/(Loss) recognized in Accumulated OCI	$	45,749		$	10,663
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	9,528		$	57,847
Ending Balance – Accumulated OCI	$	71,674		$	132,731
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(3,753	)	$	882



	For the Six Months Ended June 30,
	2013			2012
Natural Gas Price Swaps
Beginning Balance – Accumulated OCI	$	76,761		$	151,780
Gain/(Loss) recognized in Accumulated OCI	$	27,154		$	86,739
Less: Gain reclassified from Accumulated OCI into Outside Sales	$	32,241		$	105,788
Ending Balance – Accumulated OCI	$	71,674		$	132,731
Gain/(Loss) recognized in Outside Sales for ineffectiveness	$	(2,712	)	$	47

There were no amounts excluded from the assessment of hedge effectiveness in 2013 or 2012.

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 June 30, 2013						Fair Value Measurements at December 31, 2012
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	$	—	$	116,119	$	—	$	—	$	128,945	$	—

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.

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

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

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

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

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



	June 30, 2013						December 31, 2012
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	71,938		$	71,938		$	21,878		$	21,878
Restricted Cash (a)	$	—		$	—		$	68,673		$	68,673
Short-Term Notes Payable	$	(173,000	)	$	(173,000	)	$	(25,073	)	$	(25,073	)
Borrowings Under Securitization Facility	$	(40,719	)	$	(40,719	)	$	(37,846	)	$	(37,846	)
Long-Term Debt	$	(3,128,585	)	$	(3,270,812	)	$	(3,129,017	)	$	(3,378,058	)

(a) The 2012 restricted cash balance includes $48,294 and $20,379 located in current assets and other assets of the Consolidated Balance Sheet, respectively.

NOTE 14—SEGMENT INFORMATION:

CONSOL Energy has two principal business divisions: Coal and Gas. 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 six months ended June 30, 2013, the Thermal aggregated segment includes the following mines: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the six months ended June 30, 2013, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the six months ended June 30, 2013, the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge and Robinson Run 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. The principal activity of the Gas division is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, 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 Gas division but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services, general and administrative activities and other business activities. 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 (coal, gas 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.

Annually, the preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2012 gas reserve results, which are reported in the Supplemental Gas Data year ended December 31, 2012 Form 10-K, were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer in the state of Texas with over 14 years of experience in the oil and gas industry.

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



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas			All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	697,945	$	111,006	$	57,115	$	5,005		$	871,071	$	87,799	$	46,577	$	33,745		$	3,115		$	171,236		$	83,469		$	—		$	1,125,776	(A)
Sales—purchased gas	—		—		—		—			—		—		—		—			1,406			1,406			—			—			1,406
Sales—gas royalty interests	—		—		—		—			—		—		—		—			17,028			17,028			—			—			17,028
Freight—outside	—		—		—		10,125			10,125		—		—		—			—			—			—			—			10,125
Intersegment transfers	—		—		—		—			—		—		—		—			926			926			32,428			(33,354		)	—
Total Sales and Freight	$	697,945	$	111,006	$	57,115	$	15,130		$	881,196	$	87,799	$	46,577	$	33,745		$	22,475		$	190,596		$	115,897		$	(33,354	)	$	1,154,335
Earnings (Loss) Before Income Taxes	$	103,768	$	30,819	$	17,245	$	(86,354	)	$	65,478	$	22,124	$	11,680	$	(5,576	)	$	(32,838	)	$	(4,610	)	$	(883	)	$	(58,176	)	$	1,809	(B)
Segment assets										$	5,600,934											$	6,170,531		$	363,819		$	617,644		$	12,752,928	(C)
Depreciation, depletion and amortization										$	100,751											$	52,236		$	6,320		$	—		$	159,307
Capital expenditures										$	157,558											$	188,463		$	6,007		$	—		$	352,028

(A) Included in the Coal segment are sales of $157,318 to First Energy and $138,700 to Xcoal Energy & Resources each comprising over 10% of sales.

(B) Includes equity in earnings of unconsolidated affiliates of $11,526, $1,030 and $(686) for Coal, Gas and All Other, respectively.

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

Industry segment results for the three months ended June 30, 2012 are:



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal		Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas		All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	748,303	$	120,481	$	71,250	$	4,736	$	944,770	$	88,080	$	23,730	$	34,207		$	2,082		$	148,099	$	96,424		$	—		$	1,189,293	(D)
Sales—purchased gas	—		—		—		—		—		—		—		—			651			651		—			—			651
Sales—gas royalty interests	—		—		—		—		—		—		—		—			9,533			9,533		—			—			9,533
Freight—outside	—		—		—		49,472		49,472		—		—		—			—			—		—			—			49,472
Intersegment transfers	—		—		—		—		—		—		—		—			360			360		36,136			(36,496		)	—
Total Sales and Freight	$	748,303	$	120,481	$	71,250	$	54,208	$	994,242	$	88,080	$	23,730	$	34,207		$	12,626		$	158,643	$	132,560		$	(36,496	)	$	1,248,949
Earnings (Loss) Before Income Taxes	$	133,697	$	42,780	$	19,418	$	61,286	$	257,181	$	24,344	$	4,835	$	(2,410	)	$	(25,625	)	$	1,144	$	14,962		$	(61,632	)	$	211,655	(E)
Segment assets									$	5,445,502											$	5,970,939	$	360,673		$	820,782		$	12,597,896	(F)
Depreciation, depletion and amortization									$	100,684											$	47,326	$	(5,782	)	$	11,596		$	153,824
Capital expenditures									$	253,587											$	143,206	$	11,160		$	—		$	407,953


(D)	Included in the Coal segment are sales of $136,576 to First Energy and $181,566 to Xcoal Energy & Resources each comprising over 10% of sales.


(E)	Includes equity in earnings of unconsolidated affiliates of $1,483, $2,037 and $3,648 for Coal, Gas and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $21,090, $132,545 and $55,638 for Coal, Gas and All Other, respectively.

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



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas			All Other			Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	1,459,217	$	257,834	$	115,737	$	10,668		$	1,843,456	$	171,439	$	94,988	$	66,181		$	6,470		$	339,078		$	169,407		$	—		$	2,351,941	(G)
Sales—purchased gas	—		—		—		—			—		—		—		—			2,764			2,764			—			—			2,764
Sales—gas royalty interests	—		—		—		—			—		—		—		—			31,232			31,232			—			—			31,232
Freight—outside	—		—		—		24,186			24,186		—		—		—			—			—			—			—			24,186
Intersegment transfers	—		—		—		—			—		—		—		—			1,762			1,762			67,905			(69,667		)	—
Total Sales and Freight	$	1,459,217	$	257,834	$	115,737	$	34,854		$	1,867,642	$	171,439	$	94,988	$	66,181		$	42,228		$	374,836		$	237,312		$	(69,667	)	$	2,410,123
Earnings (Loss) Before Income Taxes	$	232,200	$	85,536	$	30,597	$	(189,353	)	$	158,980	$	43,436	$	25,448	$	(9,737	)	$	(64,397	)	$	(5,250	)	$	(41,435	)	$	(111,785	)	$	510	(H)
Segment assets										$	5,600,934											$	6,170,531		$	363,819		$	617,644		$	12,752,928	(I)
Depreciation, depletion and amortization										$	203,462											$	104,635		$	12,525		$	—		$	320,622
Capital expenditures										$	354,896											$	395,593		$	7,511		$	—		$	758,000

(G) Included in the Coal segment are sales of $328,300 to First Energy and $321,821 to Xcoal Energy & Resources each comprising over 10% of sales.

(H) Includes equity in earnings of unconsolidated affiliates of $12,343, $4,212 and $112 for Coal, Gas and All Other, respectively.

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

Industry segment results for the six months ended June 30, 2012 are:



	Thermal		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal		Total Coal		Coalbed Methane		Marcellus Shale		Shallow Oil and Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	1,560,356	$	293,221	$	131,818	$	13,691	$	1,999,086	$	187,615	$	47,521	$	68,580		$	4,586		$	308,302	$	193,376	$	—		$	2,500,764	(J)
Sales—purchased gas	—		—		—		—		—		—		—		—			1,490			1,490		—		—			1,490
Sales—gas royalty interests	—		—		—		—		—		—		—		—			21,739			21,739		—		—			21,739
Freight—outside	—		—		—		98,765		98,765		—		—		—			—			—		—		—			98,765
Intersegment transfers	—		—		—		—		—		—		—		—			826			826		73,345		(74,171		)	—
Total Sales and Freight	$	1,560,356	$	293,221	$	131,818	$	112,456	$	2,097,851	$	187,615	$	47,521	$	68,580		$	28,641		$	332,357	$	266,721	$	(74,171	)	$	2,622,758
Earnings (Loss) Before Income Taxes	$	262,146	$	122,121	$	35,354	$	30	$	419,651	$	60,734	$	8,086	$	(6,132	)	$	(49,044	)	$	13,644	$	19,045	$	(122,108	)	$	330,232	(K)
Segment assets									$	5,445,502											$	5,970,939	$	360,673	$	820,782		$	12,597,896	(L)
Depreciation, depletion and amortization									$	201,446											$	96,129	$	—	$	11,596		$	309,171
Capital expenditures									$	448,016											$	241,661	$	24,722	$	—		$	714,399


(J)	Included in the Coal segment are sales of $280,731 to First Energy and $319,907 to Xcoal Energy & Resources each comprising over 10% of sales.


(K)	Includes equity in earnings of unconsolidated affiliates of $6,290, $3,981 and $4,832 for Coal, Gas and All Other, respectively.

(L) Includes investments in unconsolidated equity affiliates of $21,090, $132,545 and $55,638 for Coal, Gas and All Other, respectively.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Segment Earnings Before Income Taxes for total reportable business segments	$	60,868		$	258,325		$	153,730		$	433,295
Segment (Loss) Earnings Before Income Taxes for all other businesses	(883		)	14,962			(41,435		)	19,045
Interest expense, net and other non-operating activity (M)	(56,406		)	(58,943		)	(109,066		)	(118,985		)
Other Corporate Items (M)	(1,770		)	(2,689		)	(2,719		)	(3,123		)
Earnings Before Income Taxes	$	1,809		$	211,655		$	510		$	330,232



Total Assets:	June 30,
Total Assets:	2013		2012
Segment assets for total reportable business segments	$	11,771,465	$	11,416,441
Segment assets for all other businesses	363,819		360,673
Items excluded from segment assets:
Cash and other investments (M)	45,905		186,611
Recoverable income taxes	1,930		—
Deferred tax assets	531,707		588,722
Bond issuance costs	38,102		45,449
Total Consolidated Assets	$	12,752,928	$	12,597,896

_________________________

(M) Excludes amounts specifically related to the gas 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 June 30, 2013 (unaudited):



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	172,161		$	897,541		$	53,610		$	2,464		$	1,125,776
Sales—Gas Royalty Interests	—			17,028			—			—			—			17,028
Sales—Purchased Gas	—			1,406			—			—			—			1,406
Freight—Outside	—			—			10,125			—			—			10,125
Other Income	198,207			11,235			45,706			5,404			(198,207		)	62,345
Total Revenue and Other Income	198,207			201,830			953,372			59,014			(195,743		)	1,216,680
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	4,249			125,632			660,137			53,467			12,393			855,878
Gas Royalty Interests Costs	—			13,544			—			—			(10		)	13,534
Purchased Gas Costs	—			1,061			—			—			—			1,061
Related Party Activity	35,231			—			(50,571		)	436			14,904			—
Freight Expense	—			—			10,125			—			—			10,125
Selling, General and Administrative Expenses	—			11,717			25,058			348			—			37,123
Depreciation, Depletion and Amortization	3,252			52,236			103,321			498			—			159,307
Interest Expense	50,807			2,136			1,679			10			(114		)	54,518
Taxes Other Than Income	88			—			82,507			730			—			83,325
Total Costs	93,627			206,326			832,256			55,489			27,173			1,214,871
Earnings (Loss) Before Income Taxes	104,580			(4,496		)	121,116			3,525			(222,916		)	1,809
Income Tax Expense (Benefit)	117,106			(1,747		)	(96,692		)	(4,045		)	—			14,622
Net (Loss) Income	(12,526		)	(2,749		)	217,808			7,570			(222,916		)	(12,813		)
Add: Net Loss Attributable to Noncontrolling Interest	—			287			—			—			—			287
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(12,526	)	$	(2,462	)	$	217,808		$	7,570		$	(222,916	)	$	(12,526	)

Balance Sheet at June 30, 2013 (unaudited):



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	45,267	$	26,851		$	122		$	(302	)	$	—		$	71,938
Accounts and Notes Receivable:
Trade	—		62,013			—			285,354			—			347,367
Notes Receivable	234		323,835			26,908			—			—			350,977
Other Receivables	4,449		133,895			8,436			4,489			—			151,269
Accounts Receivable—Securitized	—		—			—			40,719			—			40,719
Inventories	—		14,619			176,899			36,476			—			227,994
Deferred Income Taxes	169,905		(26,901		)	—			—			—			143,004
Recoverable Income Taxes	16,038		(14,108		)	—			—			—			1,930
Prepaid Expenses	12,795		86,893			36,494			1,461			—			137,643
Total Current Assets	248,688		607,097			248,859			368,197			—			1,472,841
Property, Plant and Equipment:
Property, Plant and Equipment	221,174		6,368,437			9,578,914			25,726			—			16,194,251
Less-Accumulated Depreciation, Depletion and Amortization	134,785		1,064,498			4,552,589			18,634			—			5,770,506
Total Property, Plant and Equipment-Net	86,389		5,303,939			5,026,325			7,092			—			10,423,745
Other Assets:
Deferred Income Taxes	820,406		(431,703		)	—			—			—			388,703
Investment in Affiliates	10,128,714		170,589			764,618			—			(10,807,824		)	256,097
Notes Receivable	184		—			1,328			—			—			1,512
Other	112,660		47,888			39,568			9,914			—			210,030
Total Other Assets	11,061,964		(213,226		)	805,514			9,914			(10,807,824		)	856,342
Total Assets	$	11,397,041	$	5,697,810		$	6,080,698		$	385,203		$	(10,807,824	)	$	12,752,928
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	193,082	$	208,852		$	48,729		$	10,752		$	—		$	461,415
Accounts Payable (Recoverable)—Related Parties	3,847,815		65,771			(4,118,674		)	153,288			51,800			—
Current Portion Long-Term Debt	1,562		5,972			5,081			807			—			13,422
Short-Term Notes Payable	—		224,800			—			—			(51,800		)	173,000
Borrowings Under Securitization Facility	—		—			—			40,719			—			40,719
Other Accrued Liabilities	140,353		64,908			582,911			10,473			—			798,645
Total Current Liabilities	4,182,812		570,303			(3,481,953		)	216,039			—			1,487,201
Long-Term Debt:	3,005,012		43,897			121,252			1,589			—			3,171,750
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions	—		—			2,820,186			—			—			2,820,186
Pneumoconiosis Benefits	—		—			177,146			—			—			177,146
Mine Closing	—		—			459,392			—			—			459,392
Gas Well Closing	—		115,802			78,144			—			—			193,946
Workers’ Compensation	—		—			155,199			319			—			155,518
Salary Retirement	109,691		—			—			—			—			109,691
Reclamation	—		—			50,051			—			—			50,051
Other	73,875		11,703			17,409			—			—			102,987
Total Deferred Credits and Other Liabilities	183,566		127,505			3,757,527			319			—			4,068,917
Total CONSOL Energy Inc. Stockholders’ Equity	4,025,651		4,956,696			5,683,872			167,256			(10,807,824		)	4,025,651
Noncontrolling Interest	—		(591		)	—			—			—			(591		)
Total Liabilities and Equity	$	11,397,041	$	5,697,810		$	6,080,698		$	385,203		$	(10,807,824	)	$	12,752,928

Income Statement for the Three Months Ended June 30, 2012 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	148,459	$	976,515	$	64,785	$	(466	)	$	1,189,293
Sales—Gas Royalty Interests	—			9,533		—		—		—			9,533
Sales—Purchased Gas	—			651		—		—		—			651
Freight—Outside	—			—		49,472		—		—			49,472
Other Income	249,780			18,098		30,352		5,215		(97,907		)	205,538
Total Revenue and Other Income	249,780			176,741		1,056,339		70,000		(98,373		)	1,454,487
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	22,351			101,695		662,457		62,811		7,575			856,889
Gas Royalty Interests Costs	—			7,131		—		—		(7		)	7,124
Purchased Gas Costs	—			869		—		—		—			869
Related Party Activity	(14,013		)	—		22,782		447		(9,216		)	—
Freight Expense	—			—		49,472		—		—			49,472
Selling, General and Administrative Expenses	—			9,313		24,185		234		—			33,732
Depreciation, Depletion and Amortization	2,895			47,326		103,085		518		—			153,824
Interest Expense	52,932			1,191		2,560		11		(101		)	56,593
Taxes Other Than Income	27			8,164		75,425		713		—			84,329
Total Costs	64,192			175,689		939,966		64,734		(1,749		)	1,242,832
Earnings (Loss) Before Income Taxes	185,588			1,052		116,373		5,266		(96,624		)	211,655
Income Tax Expense (Benefit)	32,849			326		23,788		1,982		—			58,945
Net (Loss) Income	152,739			726		92,585		3,284		(96,624		)	152,710
Add: Net Loss Attributable to Noncontrolling Interest	—			29		—		—		—			29
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	152,739		$	755	$	92,585	$	3,284	$	(96,624	)	$	152,739

Balance Sheet at December 31, 2012:



	Parent Issuer		CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	17,491	$	3,352		$	175		$	860	$	—		$	21,878
Accounts and Notes Receivable:
Trade	—		58,126			—			370,202		—			428,328
Notes Receivable	154		315,730			2,503			—		—			318,387
Other Receivables	6,335		214,748			33,289			5,159		(128,400		)	131,131
Accounts Receivable—Securitized	—		—			—			37,846		—			37,846
Inventories	—		14,133			198,269			35,364		—			247,766
Deferred Income Taxes	174,176		(26,072		)	—			—		—			148,104
Restricted Cash	—		—			48,294			—		—			48,294
Prepaid Expenses	29,589		86,186			40,215			1,370		—			157,360
Total Current Assets	227,745		666,203			322,745			450,801		(128,400		)	1,539,094
Property, Plant and Equipment:
Property, Plant and Equipment	216,448		5,956,207			9,347,370			25,179		—			15,545,204
Less-Accumulated Depreciation, Depletion and Amortization	126,048		960,613			4,249,507			18,069		—			5,354,237
Total Property, Plant and Equipment-Net	90,400		4,995,594			5,097,863			7,110		—			10,190,967
Other Assets:
Deferred Income Taxes	884,310		(439,725		)	—			—		—			444,585
Restricted Cash	—		—			20,379			—		—			20,379
Investment in Affiliates	9,917,050		143,876			769,058			—		(10,607,154		)	222,830
Notes Receivable	239		—			25,738			—		—			25,977
Other	118,938		65,935			32,016			10,188		—			227,077
Total Other Assets	10,920,537		(229,914		)	847,191			10,188		(10,607,154		)	940,848
Total Assets	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909
Liabilities and Equity:
Current Liabilities:
Accounts Payable	$	177,734	$	166,182		$	154,936		$	9,130	$	—		$	507,982
Accounts Payable (Recoverable)-Related Parties	3,599,216		23,981			(3,749,584		)	254,787		(128,400		)	—
Current Portion of Long-Term Debt	1,554		5,953			5,222			756		—			13,485
Short-Term Notes Payable	25,073		—			—			—		—			25,073
Accrued Income Taxes	20,488		13,731			—			—		—			34,219
Borrowings Under Securitization Facility	—		—			—			37,846		—			37,846
Other Accrued Liabilities	135,407		57,074			566,485			9,528		—			768,494
Total Current Liabilities	3,959,472		266,921			(3,022,941		)	312,047		(128,400		)	1,387,099
Long-Term Debt:	3,005,515		46,081			121,523			1,467		—			3,174,586
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions	—		—			2,832,401			—		—			2,832,401
Pneumoconiosis Benefits	—		—			174,781			—		—			174,781
Mine Closing	—		—			446,727			—		—			446,727
Gas Well Closing	—		80,097			68,831			—		—			148,928
Workers’ Compensation	—		—			155,342			306		—			155,648
Salary Retirement	218,004		—			—			—		—			218,004
Reclamation	—		—			47,965			—		—			47,965
Other	101,899		24,518			4,608			—		—			131,025
Total Deferred Credits and Other Liabilities	319,903		104,615			3,730,655			306		—			4,155,479
Total CONSOL Energy Inc. Stockholders’ Equity	3,953,792		5,014,313			5,438,562			154,279		(10,607,154		)	3,953,792
Noncontrolling Interest	—		(47		)	—			—		—			(47		)
Total Liabilities and Equity	$	11,238,682	$	5,431,883		$	6,267,799		$	468,099	$	(10,735,554	)	$	12,670,909

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



	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Sales—Outside	$	—		$	340,840		$	1,901,698		$	107,663		$	1,740		$	2,351,941
Sales—Gas Royalty Interests	—			31,232			—			—			—			31,232
Sales—Purchased Gas	—			2,764			—			—			—			2,764
Freight—Outside	—			—			24,186			—			—			24,186
Other Income	276,183			24,459			60,961			10,777			(276,183		)	96,197
Total Revenue and Other Income	276,183			399,295			1,986,845			118,440			(274,443		)	2,506,320
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	80,239			239,984			1,341,842			107,193			19,583			1,788,841
Gas Royalty Interests Costs	—			25,361			—			—			(21		)	25,340
Purchased Gas Costs	—			2,020			—			—			—			2,020
Related Party Activity	22,675			—			(58,349		)	840			34,834			—
Freight Expense	—			—			24,186			—			—			24,186
Selling, General and Administrative Expenses	—			21,829			48,305			659			—			70,793
Depreciation, Depletion and Amortization	6,447			104,635			208,558			982			—			320,622
Interest Expense	100,976			3,797			3,323			21			(221		)	107,896
Taxes Other Than Income	265			6,698			157,513			1,636			—			166,112
Total Costs	210,602			404,324			1,725,378			111,331			54,175			2,505,810
Earnings (Loss) Before Income Taxes	65,581			(5,029		)	261,467			7,109			(328,618		)	510
Income Tax Expense (Benefit)	79,671			(1,955		)	(59,883		)	(2,689		)	—			15,144
Net (Loss) Income	(14,090		)	(3,074		)	321,350			9,798			(328,618		)	(14,634		)
Add: Net Loss Attributable to Noncontrolling Interest	—			544			—			—			—			544
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	(14,090	)	$	(2,530	)	$	321,350		$	9,798		$	(328,618	)	$	(14,090	)

Income Statement for the Six Months Ended June 30, 2012 (unaudited):



	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	309,128	$	2,058,803	$	133,807	$	(974	)	$	2,500,764
Sales—Gas Royalty Interests	—			21,739		—		—		—			21,739
Sales—Purchased Gas	—			1,490		—		—		—			1,490
Freight—Outside	—			—		98,765		—		—			98,765
Other Income	417,765			34,403		60,055		11,172		(264,896		)	258,499
Total Revenue and Other Income	417,765			366,760		2,217,623		144,979		(265,870		)	2,881,257
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	71,531			200,340		1,345,213		129,227		14,619			1,760,930
Gas Royalty Interests Costs	—			17,386		—		—		(13		)	17,373
Purchased Gas Costs	—			1,386		—		—		—			1,386
Related Party Activity	(7,000		)	—		24,040		949		(17,989		)	—
Freight Expense	—			—		98,765		—		—			98,765
Selling, General and Administrative Expenses	—			19,293		52,757		681		—			72,731
Depreciation, Depletion and Amortization	5,816			96,129		206,185		1,041		—			309,171
Interest Expense	107,694			2,409		4,789		22		(201		)	114,713
Taxes Other Than Income	663			16,364		157,396		1,533		—			175,956
Total Costs	178,704			353,307		1,889,145		133,453		(3,584		)	2,551,025
Earnings (Loss) Before Income Taxes	239,061			13,453		328,478		11,526		(262,286		)	330,232
Income Tax Expense (Benefit)	(10,874		)	5,273		81,577		4,350		—			80,326
Net (Loss) Income	249,935			8,180		246,901		7,176		(262,286		)	249,906
Add: Net Loss Attributable to Noncontrolling Interest	—			29		—		—		—			29
Net (Loss) Income Attributable to CONSOL Energy Inc. Shareholders	$	249,935		$	8,209	$	246,901	$	7,176	$	(262,286	)	$	249,935

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by Operating Activities	$	35,486		$	263,284		$	46,545		$	(3,721	)	$	51,800		$	393,394
Cash Flows from Investing Activities:
Capital Expenditures	$	(7,511	)	$	(395,593	)	$	(354,896	)	$	—		$	—		$	(758,000	)
Change in Restricted Cash	—			—			68,673			—			—			68,673
Proceeds from Sales of Assets	—			5,644			235,144			13			—			240,801
Net Investments In Equity Affiliates	—			(22,501		)	5,901			—			—			(16,600		)
Net Cash (Used in) Provided by Investing Activities	$	(7,511	)	$	(412,450	)	$	(45,178	)	$	13		$	—		$	(465,126	)
Cash Flows from Financing Activities:
Proceeds from (Payments on) Short-Term Borrowings	$	—		$	224,800		$	—		$	—		$	(51,800	)	$	173,000
Payments on Miscellaneous Borrowings	(26,280		)	—			(3,555		)	(327		)	—			(30,162		)
Proceeds from Securitization Facility	—			—			—			2,873			—			2,873
Dividends (Paid) Received	21,399			(50,000		)	—			—			—			(28,601		)
Proceeds from Issuance of Common Stock	2,497			—			—			—			—			2,497
Other Financing Activities	2,185			—			—			—			—			2,185
Net Cash Provided by (Used in) Financing Activities	$	(199	)	$	174,800		$	(3,555	)	$	2,546		$	(51,800	)	$	121,792

Cash Flow for the Six Months Ended June 30, 2012 (unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	271,127		$	124,367		$	(28,281	)	$	736		$	—	$	367,949
Cash Flows from Investing Activities:
Capital Expenditures	$	(24,722	)	$	(241,661	)	$	(448,016	)	$	—		$	—	$	(714,399	)
Investments in Equity Affiliates	—			(35,150		)	(750		)	—			—		(35,900		)
Distributions from Equity Affiliates	—			3,500			10,561			—			—		14,061
Proceeds from Sales of Assets	169,500			30,249			52,469			11			—		252,229
Net Cash (Used in) Provided by Investing Activities	$	144,778		$	(243,062	)	$	(385,736	)	$	11		$	—	$	(484,009	)
Cash Flows from Financing Activities:
Dividends Paid	$	143,167		$	(200,000	)	$	—		$	—		$	—	$	(56,833	)
Other Financing Activities	1,580			(3,751		)	2			(467		)	—		(2,636		)
Net Cash Provided by (Used in) Financing Activities	$	144,747		$	(203,751	)	$	2		$	(467	)	$	—	$	(59,469	)

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(12,526	)	$	(2,749	)	$	217,808	$	7,570	$	(222,916	)	$	(12,813	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	42,904			—			42,904		—		(42,904		)	42,904
Net (Decrease) Increase in the Value of Cash Flow Hedge	45,749			45,749			—		—		(45,749		)	45,749
Reclassification of Cash Flow Hedge from OCI to Earnings	(9,528		)	(9,528		)	—		—		9,528			(9,528		)
Other Comprehensive (Loss) Income:	79,125			36,221			42,904		—		(79,125		)	79,125
Comprehensive Income (Loss)	66,599			33,472			260,712		7,570		(302,041		)	66,312
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			287			—		—		—			287
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	66,599		$	33,759		$	260,712	$	7,570	$	(302,041	)	$	66,599

Statement of Comprehensive Income for the Three Months Ended June 30, 2012 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	152,739		$	726		$	92,585	$	3,284	$	(96,624	)	$	152,710
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	7,586			—			7,586		—		(7,586		)	7,586
Net Increase (Decrease) in the Value of Cash Flow Hedge	10,663			10,663			—		—		(10,663		)	10,663
Reclassification of Cash Flow Hedge from OCI to Earnings	(57,847		)	(57,847		)	—		—		57,847			(57,847		)
Other Comprehensive Income (Loss):	(39,598		)	(47,184		)	7,586		—		39,598			(39,598		)
Comprehensive Income (Loss)	113,141			(46,458		)	100,171		3,284		(57,026		)	113,112
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			29			—		—		—			29
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	113,141		$	(46,429	)	$	100,171	$	3,284	$	(57,026	)	$	113,141

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



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net (Loss) Income	$	(14,090	)	$	(3,074	)	$	321,350	$	9,798	$	(328,618	)	$	(14,634	)
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	88,661			—			88,661		—		(88,661		)	88,661
Net (Decrease) Increase in the Value of Cash Flow Hedge	27,154			27,154			—		—		(27,154		)	27,154
Reclassification of Cash Flow Hedge from OCI to Earnings	(32,241		)	(32,241		)	—		—		32,241			(32,241		)
Other Comprehensive Income (Loss):	83,574			(5,087		)	88,661		—		(83,574		)	83,574
Comprehensive Income (Loss)	69,484			(8,161		)	410,011		9,798		(412,192		)	68,940
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			544			—		—		—			544
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	69,484		$	(7,617	)	$	410,011	$	9,798	$	(412,192	)	$	69,484

Statement of Comprehensive Income for the Six Months Ended June 30, 2012 (Unaudited):



	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors		Non- Guarantors		Elimination			Consolidated
Net Income (Loss)	$	249,935		$	8,180		$	246,901	$	7,176	$	(262,286	)	$	249,906
Other Comprehensive Income (Loss):
Actuarially Determined Long-Term Liability Adjustments	67,159			—			67,159		—		(67,159		)	67,159
Net Increase (Decrease) in the Value of Cash Flow Hedge	86,739			86,739			—		—		(86,739		)	86,739
Reclassification of Cash Flow Hedge from OCI to Earnings	(105,788		)	(105,788		)	—		—		105,788			(105,788		)
Other Comprehensive Income (Loss):	48,110			(19,049		)	67,159		—		(48,110		)	48,110
Comprehensive Income (Loss)	298,045			(10,869		)	314,060		7,176		(310,396		)	298,016
Add: Comprehensive Loss Attributable to Noncontrolling Interest	—			29			—		—		—			29
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	298,045		$	(10,840	)	$	314,060	$	7,176	$	(310,396	)	$	298,045

NOTE 16—RELATED PARTY TRANSACTIONS:

CONE Gathering LLC Related Party Transactions

During the six months ended June 30, 2013, 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 $6,129 and $13,456 for the three and six months ended June 30, 2013, respectively, and were $4,262 and $7,724 for the three and six months ended June 30, 2012, respectively, which were included in Cost of Goods Sold on the Consolidated Statements of Income.

As of June 30, 2013 and December 31, 2012, CONSOL Energy and CNX Gas Company had a net payable of $1,509 and $3,142, respectively, due CONE which was comprised of the following items:



	June 30,			December 31,
	2013			2012			Location on Balance Sheet
Reimbursement for CONE Expenses	$	(733	)	$	(1,336	)	Accounts Receivable–Other
Reimbursement for Services Provided to CONE	(153		)	(341		)	Accounts Receivable–Other
CONE Gathering Capital Reimbursement	—			(18		)	Accounts Receivable–Other
CONE Gathering Fee Payable	2,395			4,837			Accounts Payable
Net Payable due CONE	$	1,509		$	3,142

NOTE 17—RECENT ACCOUNTING PRONOUNCEMENTS:

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: (a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.


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

General

After a strong market rally early in the second quarter from extended winter weather, natural gas prices began to decline below $4.00 per MMBtu in June from a cooler than expected start to summer and power generation switching back to coal from natural gas. Despite the decrease, natural gas prices remained significantly above 2012 levels. During the second quarter, cooler than normal temperatures slowly applied downward pressure on both thermal coal and natural gas prices as the market cautiously awaited the arrival of summer heat. By the quarter's end, however, the U.S. had experienced 12% fewer cooling degree days than the previous year which negatively impacted thermal coal and natural gas demand. From a fuel-mix perspective, coal-fired electric generation increased by 10% year over year, while higher natural gas prices reduced gas consumption by 18% over the same period. Despite the cooler weather, natural gas underground inventory levels remained below the five year average. Although global economic uncertainties persisted, continued disciplined coal production, slow natural gas production growth and decreasing natural gas net imports helped slow inventory growth and keep prices stable.

Second quarter coal consumption was aided by increased natural gas prices in April and May. As natural gas prices rose above $4.00 per MMbtu, coal fired electric generation continued to be strong. Early government estimates show that coal-fired generation produced 39% of U.S. power during the second quarter compared with 34% during the same period in 2012, and 40% in the first quarter 2013. Conventional hydropower and nuclear generation gained share during the second quarter, at the expense of coal and natural gas generation. Utility coal stockpiles declined throughout the quarter versus 2012 periods. Increased natural gas prices and domestic coal production cuts contributed to continued stabilization of coal prices.

In the longer term, the outlook for domestic thermal coal continues to face regulatory challenges. In line with President Obama's climate change initiative and the upcoming 2015 deadline for the U.S. Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) rule, utilities are retiring non-compliant coal-fired units and less efficient coal-fired units.

Internationally, U.S. exports are expected to decline in 2013 after a record year in 2012. After a strong first quarter, early government data for second quarter thermal exports shows a 30% decrease over the year ago period. For the first half of 2013, thermal coal exports are down 10% over the 2012 first half. Low international pricing, in combination with a stronger domestic market, contributed to the decline. Longer-term fundamentals for U.S. thermal coal exports remain favorable as subsidized mining in Europe is phased out, nuclear growth plans are curtailed, and coal continues to maintain a cost advantage over other more expensive oil-linked fuels.

While the U.S. second quarter benchmark price for premium metallurgical coal rose 4% over the prior quarter, spot prices declined to multi-year lows. Price deterioration in the spot market helped push the quarterly benchmark price in the U.S. third quarter 16% lower than the second quarter. The low price environment is indicative of the continued oversupplied position of the global metallurgical coal market.

Global steel production in 2013 has grown at a 4% annualized rate over 2012, largely driven by record production in China. Steel production outside of China has remained under pressure as a result of limited demand growth and steel mill overcapacity. In response to the weak metallurgical coal market, CONSOL Energy has positioned itself by reducing metallurgical coal production in 2013 and increasing thermal coal output.

CONSOL Energy's coal sales outlook is as follows:



	Q3 2013		2013		2014		2015
Estimated Coal Sales (millions of tons)	13.4 - 13.9		55.5 - 57.5		60.4		61.7
Est. Low-Vol Met Sales	0.7 -0.9		4.0-4.2		4.7		5.2
Tonnage: Firm	0.2		2.8		—		—
Avg. Price: Sold (Firm)	$	113.81	$	103.34	$	—	$	—
Est. High-Vol Met Sales	0.6+		2.6+		4.8		6.4
Tonnage: Firm	0.4		2.4		0.2		0.2
Avg. Price: Sold (Firm)	$	60.55	$	63.67	$	75.53	$	74.74
Est. Thermal Sales	12.3+		49.9+		50.9		50.1
Tonnage: Firm	12.3		49.8		28.1		14.8
Avg. Price: Sold (Firm)	$	59.02	$	58.93	$	60.45	$	60.99

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. N/A means not available or not forecast. CONSOL Energy has chosen not to forecast prices for open tonnage due to ongoing customer negotiations. In the thermal sales category, the open tonnage includes two items: sold, but unpriced tons and collared tons. Collared tons in 2014 are 7.0 million tons, with a ceiling of $55.90 per ton and a floor of $46.32 per ton. Collared tons in 2015 are 8.7 million tons, with a ceiling of $57.43 per ton and a floor of $44.86 per ton. Calendar year 2013 includes 0.1 million tons from Amonate. The Amonate tons are not included in the category breakdowns.

CONSOL Energy expects Capital investment costs for the BMX Mine to total $710 million. The increase from the prior estimate is due, in part, to a lower sales price for development tons, which increases the dollars being capitalized during the development phase.

CONSOL Energy expects its net gas production to be between 170 – 175 Bcfe for the year. Third quarter gas production, net to CONSOL Energy, is expected to be approximately 43 – 45 Bcfe.

Several significant events occurred in the six months ended June 30, 2013. These events include the following:

•

On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County, Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified and containment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. This event resulted in a pre-tax expense of $38.4 million in the six months ended June 30, 2013.


•	On June 24, 2013, CONSOL Energy closed the sale of the Potomac coal reserves located in Grant and Tucker Counties in West Virginia. Cash proceeds from the sale were $25.0 million. The transaction resulted in a $24.7 million gain on the sale of assets.

•

Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company's salary retirement pension plan exceeding the annual projected service and interest costs of the plan. The pension settlement resulted in $32.2 million pre-tax expense adjustment. Many of the lump sum payments in the six months ended June 30, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive program. Also, pension settlement required the pension plan to be remeasured using updated assumptions at June 30, 2013. The updated assumptions include resetting the discount rate used in the actuarial calculation. See Note 3 - Components of Pension and Other Postretirement Benefit (OPEB) Plans Net Periodic Benefit Costs, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details of the updated assumptions.

•

A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the six months ended June 30, 2013. As part of the title defect process the company is working through with its joint venture partner, Noble Energy, CONSOL Energy conceded title defects on acreage which had a book value to CONSOL Energy of $8.8 million. See Note 8 - Property, Plant and Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

•

CNX Gas Company 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 $46.3 million as an up-front bonus payment at closing. Approximately 7.6% percent

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 forgoes the bonus. Our joint venture partner, Noble Energy, has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs during the three months ended June 30, 2013.

•

In the six months ended June 30, 2013, an agreement in principle was reached for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010 in principle. The total settlement provides for a payment to the plaintiffs of $42.73 million, of which the company expects to pay $20.20 million. On May 8, 2013, the parties executed and filed with the Court a stipulation and agreement of compromise and settlement. A settlement hearing has been scheduled by the Court on August 23, 2013. See Note 11 - Commitments and Contingencies, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

CONSOL Energy continues to manage several significant matters that may affect our business and impact our financial results in the future including the following:

•

The Cross States Air Pollution Rule (CSAPR) was finalized by the Environmental Protection Agency (EPA) in July 2011. The rule required reductions in SO2 and NOx emissions in the eastern U.S. by January 1, 2012 (phase 1) and January 1, 2014 (phase 2). However, CSAPR was vacated by a three-judge panel of the D.C. Circuit on August 21, 2012, and the full D.C. Circuit declined to hear the case in January 2013. EPA and environmental groups appealed the decision to the Supreme Court on March 29, 2013. Until legal challenges are resolved and/or EPA develops a replacement rule, the Clean Air Interstate Rule (CAIR) will remain in effect.


•	On July 9, 2013, Pennsylvania Governor, Tom Corbett signed the Oil and Gas Lease Act (SB 529). The Act reinstated the Guaranteed Minimum Royalty Act of 1979 and it permits pooling of already leased acreage. The Act does not authorize forced pooling.


•	Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include increased scrutiny of existing safety regulations and the development of new safety regulations and additional environmental restrictions.


•	Federal and state environmental regulators are reviewing our operations more closely and are more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays.

•

Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. OSM has indicated that it will not issue a draft rule or a draft environmental impact statement until sometime in 2014. Other examples are the Mercury and Air Toxic Standards (MATS) (remanded by the court and re-proposed by the EPA in November 2012) and the Utility Maximum Achievable Control Technology (Utility MACTS) rules issued by the EPA. These new regulations set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOx. The EPA reconsidered the UMACT rules and recently finalized revised new source performance standards for coal based power plants which raised some emission limits. The standards remain stringent and costly for compliance. On April 18, 2012, the EPA published new final New Source Performance Standards for gas wells and related facilities. These rules apply to wells that were hydraulically fractured after August 23, 2011 and require the implementation by January 1, 2015 of technologies that capture the gas that is currently vented or flared during completion (hydrofracturing) of a well. Low pressure wells, including coalbed methane wells, are excluded from these new standards.

•

In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide emissions from coal powered electric generating units. The proposed rules will apply to new power plants and to existing plants that make major modifications. If the rules are adopted as proposed, the only new coal fired power plants that will be able to meet the proposed emission limits will be coal fired plants with carbon dioxide capture and storage (CCS). Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal fired electric generation units uneconomical compared to new gas fired electric generation units. Thus, if finalized the proposed rules could seriously threaten the construction of new coal fired electric generating units. EPA did not meet an April 13, 2013 deadline to publish final rules and, according to the EPA, no specific timetable is set to publish the final rules.


•	CONSOL Energy surface coal mining operations in West Virginia are subject to several citizen suits and several citizen groups' Notices of Intent to Sue relating to alleged violations of water discharge permits from our coal mining

operations. In each of these matters, CONSOL Energy investigates the complaints, if necessary develops and implements compliance plans, and defends the citizen suits as appropriate.

•

In late June 2012, CONSOL Energy received informal notification from the Pennsylvania Department of Environmental Protection of the Department's intent pursuant to a Technical Guidance Document entitled “Surface Water Protection-Underground Bituminous Coal Mining” to require a change in the mine plan of a pending application for a permit for expansion of the Company's Bailey longwall mine. If ultimately required, this change in mine plan could have a material effect on CONSOL Energy's forecasted production for 2015. Although CONSOL Energy does not agree that a modification of its mining plan is necessary to comply with applicable regulatory performance standards, CONSOL Energy is currently reviewing the notification and any modifications that would be required if CONSOL Energy is compelled to modify its application.

•

Additional pension settlement charges are reasonably possible to occur throughout the remainder of 2013. When lump sum payments from the pension plan exceed the service and interest expense, pension settlement accounting requires unamortized actuarial gains and losses related to the lump sum payouts to be amortized immediately. The threshold for pension settlement was reached as of March 31, 2013 and the corresponding charge has been recognized as discussed above. Additional pension settlement charges throughout the remainder of 2013 could be material to the financial results of CONSOL Energy.


•	For 2013, CONSOL Energy has stepped up its asset sale process to include coal and gas transportation infrastructure, in order to capitalize on the current market environment and to re-invest proceeds in higher return projects. As previously announced, a process is in place to evaluate and potentially monetize several assets this year as long as fair value is received for those assets.


•	CONSOL Energy is currently evaluating our overall corporate structure to consider different alternatives to unlock additional value for shareholders.

Results of Operations

Three Months Ended June 30, 2013 Compared with Three Months Ended June 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $13 million, or $(0.05) per diluted share, for the three months ended June 30, 2013. Net income attributable to CONSOL Energy shareholders was $153 million, or $0.67 per diluted share, for the three months ended June 30, 2012.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $65 million of earnings before income tax for the three months ended June 30, 2013 compared to $257 million for the three months ended June 30, 2012. The total coal division sold 13.8 million tons of coal produced from CONSOL Energy mines for the three months ended June 30, 2013 compared to 14.4 million tons for the three months ended June 30, 2012.

The average sales price and total costs per ton for all active coal operations were as follows:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	62.74	$	65.58	$	(2.84	)	(4.3	)%
Average Cost of Goods Sold per ton	51.87		52.04		(0.17		)	(0.3	)%
Margin per ton sold	$	10.87	$	13.54	$	(2.67	)	(19.7	)%

The lower average sales price per ton sold is due to weakened pricing in the global metallurgical and domestic thermal coal markets, along with a reduction in sales tons in the period-to-period comparison. The average coal sales price in the 2013 period was also lower due to the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013.

Changes in the average cost of goods sold per ton were primarily related to the following items:


•	Direct operating costs improved primarily due to a decrease in all direct operating costs at the Blacksville No. 2 Mine which is the result of the mine being idled until May 20th due to the fire, as previously discussed. Costs were also improved due to the shutdown of the Fola Mining Complex in August 2012.


•	Average direct operating costs were impaired due to CONSOL Energy entering into several new leases for various types of mining equipment at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.


•	Direct services to operations are improved due to a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.


•	Depreciation, depletion and amortization was improved primarily due to lower expense at the Blacksville No. 2 Mine related to the mine being shut down due to the fire, the shutdown of operations at the Fola Mining Complex and the timing of assets going into service or being fully depreciated.

The total gas division includes CBM, Shallow Oil and Gas, Marcellus and other gas. The total gas division had a $5 million loss before income tax for the three months ended June 30, 2013 compared to $1 million of income before income tax for the three months ended June 30, 2012. Total gas production was 38.6 billion cubic feet for the three months ended June 30, 2013 compared to 37.3 billion cubic feet for the three months ended June 30, 2012. Total gas volumes increased primarily as a result of the on-going Marcellus drilling program.

The average sales price and total costs for all active gas operations were as follows:



	For the Three Months Ended June 30,
	2013		2012		Variance		Percent Change
Average Sales Price per thousand cubic feet sold	$	4.46	$	3.98	$	0.48	12.1%
Average Costs per thousand cubic feet sold	3.77		3.34		0.43		12.9%
Margin per thousand cubic feet sold	$	0.69	$	0.64	$	0.05	7.8%

Total gas division outside sales revenues were $173 million for the three months ended June 30, 2013 compared to $149 million for the three months ended June 30, 2012. The increase was primarily due to the 3.5% increase in volumes sold, along with the a 12.1% increase in average price per thousand cubic feet sold. The increase in average sales price is the result of the increase in general market prices and sales of natural gas liquids and condensate, partially offset by various gas swap transactions that occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 19.7 billion cubic feet of our produced gas sales volumes for the three months ended June 30, 2013 at an average price of $4.73 per thousand cubic feet. These financial hedges represented 19.1 billion cubic feet of our produced gas sales volumes for the three months ended June 30, 2012 at an average price of $5.25 per thousand cubic feet.

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


•	Gathering costs increased in the period-to-period comparison due to higher firm transportation costs and increased processing fees associated with natural gas liquids.


•	Lifting costs increased due to higher accretion expense related to the estimated well plugging liability. Road repair and maintenance costs also increased in the current period.


•	Depreciation, depletion and amortization increased due to higher units-of-production rates for producing properties.


•	These were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling program. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

The other segment includes industrial supplies activity, terminal, river and dock service activity, income taxes and other business activities not assigned to the coal or gas segment.

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



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Consulting and professional services	$	8	$	5	$	3		60.0	%
Contributions	5		3		2			66.7	%
Advertising and promotion	2		2		—			—	%
Employee wages and related expenses	13		15		(2		)	(13.3	)%
Miscellaneous	7		7		—			—	%
Total Company General and administrative Expenses	$	35	$	32	$	3		9.4	%

Total Company General and administrative Expenses changed due to the following:


•	Consulting and professional services increased $3 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which are individually significant.


•	Contributions increased $2 million related to various transactions that occurred throughout both periods, none of which are individually significant.


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


•	Employee wages and related expenses decreased $2 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit expenses (OPEB) in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.


•	Miscellaneous General and administrative expenses remained consistent in the period-to-period comparison.

and a increase in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31. See Note 3 - Components of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs and Note 4 - Components of Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements for additional detail of the total Company expense decrease.

TOTAL COAL SEGMENT ANALYSIS for the three months ended June 30, 2013 compared to the three months ended June 30, 2012:

The coal segment contributed $65 million of earnings before income tax in the three months ended June 30, 2013 compared to $257 million in the three months ended June 30, 2012. Variances by the individual coal segments are discussed below.



	For the Three Months Ended														Difference to Three Months Ended
	June 30, 2013														June 30, 2012
	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	$	698		$	57	$	111		$	—		$	866		$	(50	)	$	(14	)	$	(10	)	$	(2	)	$	(76	)
Purchased Coal	—			—		—			5			5			—			—			—			2			2
Total Outside Sales	698			57		111			5			871			(50		)	(14		)	(10		)	—			(74		)
Freight Revenue	—			—		—			10			10			—			—			—			(39		)	(39		)
Other Income	1			1		—			46			48			1			—			—			(138		)	(137		)
Total Revenue and Other Income	699			58		111			61			929			(49		)	(14		)	(10		)	(177		)	(250		)
Costs and Expenses:
Beginning inventory costs	44			—		8			—			52			(66		)	—			(7		)	—			(73		)
Total direct operating costs	369			26		53			83			531			(7		)	(7		)	(3		)	49			32
Total royalty/production taxes	50			3		7			—			60			(1		)	(1		)	(2		)	(1		)	(5		)
Total direct services to operations	60			4		6			36			106			(6		)	(2		)	1			(50		)	(57		)
Total retirement and disability	43			3		6			5			57			(1		)	—			(2		)	2			(1		)
Depreciation, depletion and amortization	72			5		9			14			100			(5		)	(2		)	(2		)	10			1
Ending inventory costs	(43		)	—		(9		)	—			(52		)	67			—			17			—			84
Total Costs and Expenses	595			41		80			138			854			(19		)	(12		)	2			10			(19		)
Freight Expense	—			—		—			10			10			—			—			—			(39		)	(39		)
Total Costs	595			41		80			148			864			(19		)	(12		)	2			(29		)	(58		)
Earnings (Loss) Before Income Taxes	$	104		$	17	$	31		$	(87	)	$	65		$	(30	)	$	(2	)	$	(12	)	$	(148	)	$	(192	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $104 million to total Company earnings before income tax for the three months ended June 30, 2013 and $134 million for the three months ended June 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	11.8		12.2		(0.4		)	(3.3	)%
Average Sales Price Per Thermal Ton Sold	$	59.39	$	61.47	$	(2.08	)	(3.4	)%

Beginning Inventory Costs Per Thermal Ton	$	50.57	$	55.60	$	(5.03	)	(9.0	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	31.60	$	30.96	$	0.64		2.1	%
Total Royalty/Production Taxes Per Thermal Ton Produced	4.26		4.18		0.08			1.9	%
Total Direct Services to Operations Per Thermal Ton Produced	5.17		5.42		(0.25		)	(4.6	)%
Total Retirement and Disability Per Thermal Ton Produced	3.68		3.62		0.06			1.7	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	6.20		6.36		(0.16		)	(2.5	)%
Total Production Costs Per Thermal Ton Produced	$	50.91	$	50.54	$	0.37		0.7	%

Ending Inventory Costs Per Thermal Ton	$	55.36	$	56.03	$	(0.67	)	(1.2	)%

Total Costs Per Thermal Ton Sold	$	50.60	$	50.50	$	0.10		0.2	%
Average Margin Per Thermal Ton Sold	$	8.79	$	10.97	$	(2.18	)	(19.9	)%

Thermal coal revenue was $699 million for the three months ended June 30, 2013 compared to $748 million for the three months ended June 30, 2012. The $49 million decrease was attributable to a $2.08 per ton lower average sales price and 0.4 million reduction in tons sold. The lower average thermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013. The reduction in tons was partially due to the Blacksville No. 2 Mine being idled for most of the quarter as a result of the mine fire that was previously discussed. Also, 0.5 million tons of thermal coal were priced on the export market at an average sales price of $68.68 per ton for the three months ended June 30, 2013 compared to 2.3 million tons at an average price of $55.09 per ton for the three months ended June 30, 2012.

Total cost of goods sold are comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for thermal coal was $595 million for the three months ended June 30, 2013, or $19 million lower than the $614 million for the three months ended June 30, 2012. Total cost of goods sold for thermal coal was $50.60 per ton in the three months ended June 30, 2013 compared to $50.50 per ton in the three months ended June 30, 2012. The decrease in total dollars and increase in unit costs per thermal ton produced was due to the items described below.


•	In 2013, CONSOL Energy entered into several new leases for various mining equipment, which resulted in higher cost per ton produced in the period-to-period comparison.


•	The Blacksville No. 2 mine was idled in 2013 until May 20th due to the fire that was previously discussed. This resulted in a reduction in all direct operating costs.


•	The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.

Royalties and production taxes were $50 million, or improved $1 million in the current period due primarily to the shutdown of the Fola Mining Complex in August 2012, as previously discussed.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The cost of these support services was $60 million in the current period compared to $66 million in the prior period. Direct services to the operations were $5.17 per ton produced in the current period compared to $5.42 per ton produced in the prior period. Changes in the average direct service to operations cost per thermal ton produced were primarily related to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as previously discussed.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the thermal coal segment were $43 million for the three months ended June 30, 2013 compared to $44 million for the three months ended June 30, 2012. The decrease in the thermal coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan that occurred June 30, 2012. These improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.

Depreciation, depletion and amortization for the thermal coal segment was $72 million for the three months ended June 30, 2013 compared to $77 million for the three months ended June 30, 2012. Unit costs per thermal ton produced were lower in the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to production being halted at the Blacksville No. 2 Mine for most of the 2013 period due to the fire. This resulted in no amortization or depletion expense for that period. Unit costs were also improved due to the idling of the Fola Mining Complex in 2012.

Changes in thermal coal inventory volumes and carrying value resulted in $1 million of cost of goods sold in the three months ended June 30, 2013 and had no impact in the three months ended June 30, 2012. Thermal coal inventory was 0.8 million tons at June 30, 2013 compared to 2.0 million tons at June 30, 2012.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $17 million to total Company earnings before income tax for the three months ended June 30, 2013 compared to $19 million for the three months ended June 30, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	0.9		1.2		(0.3		)	(25.0	)%
Average Sales Price Per High Vol Met Ton Sold	$	62.50	$	59.94	$	2.56		4.3	%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	29.12	$	27.88	$	1.24		4.4	%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	2.88		3.01		(0.13		)	(4.3	)%
Total Direct Services to Operations Per High Vol Met Ton Produced	4.53		4.85		(0.32		)	(6.6	)%
Total Retirement and Disability Per High Vol Met Ton Produced	2.86		2.74		0.12			4.4	%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.62		6.46		(0.84		)	(13.0	)%
Total Production Costs Per High Vol Met Ton Produced	$	45.01	$	44.94	$	0.07		0.2	%

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

Total Costs Per High Vol Met Ton Sold	$	45.01	$	44.94	$	0.07		0.2	%
Margin Per High Vol Met Ton Sold	$	17.49	$	15.00	$	2.49		16.6	%

High volatile metallurgical coal revenue was $58 million for the three months ended June 30, 2013 compared to $72 million for the three months ended June 30, 2012. Average sales prices for high volatile metallurgical coal increased $2.56 per ton in a period-to-period comparison. CONSOL Energy priced 0.8 million tons of high volatile metallurgical coal in the export market at an average sales price of $60.83 per ton for the three months ended June 30, 2013 compared to 1.1 million tons at an average price of $57.30 per ton for the three months ended June 30, 2012. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $41 million for the three months ended June 30, 2013, or $12 million lower than the $53 million for the three months ended June 30, 2012. Total cost of goods sold for high volatile metallurgical coal was $45.01 per ton in the three months ended June 30, 2013 compared to $44.94 per ton in the three months ended June 30, 2012. The increase in cost of goods sold per high volatile metallurgical ton was due to the items described below.

Royalties and production taxes were $3 million or improved $1 million in the current period due primarily to the shutdown of the Fola Mining Complex in August 2012, as previously discussed.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for high volatile metallurgical coal were $4 million in the current period compared to $6 million in the prior period. Decreased costs were attributable to lower subsidence costs due to the timing and nature of properties undermined. Direct services to the operations for high volatile metallurgical coal were $4.53 per ton produced in the current period compared to $4.85 per ton produced in the prior period. Changes in the average direct service to operations cost per ton for high volatile metallurgical coal produced were primarily related to lower subsidence expenses, offset, in part, by lower tons produced.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the high volatile metallurgical coal segment were $3 million for the three months ended June 30, 2013 and June 30, 2012. Even though total dollars remained consistent, unit costs were negatively impacted due to the reduction in volumes.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $5 million for the three months ended June 30, 2013 compared to $7 million in the three months ended June 30, 2012. Unit costs per high volatile ton produced were lower in the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to the shutdown of the Fola Mining Complex in August 2012.

There were no changes in volumes or carrying value of coal inventory in the three months ended June 30, 2013 and June 30, 2012. There was no high volatile metallurgical coal inventory at June 30, 2013 or June 30, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $31 million to total Company earnings before income tax in the three months ended June 30, 2013 compared to $43 million in the three months ended June 30, 2012. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	1.1		1.0		0.1			10.0	%
Average Sales Price Per Low Vol Met Ton Sold	$	97.54	$	123.71	$	(26.17	)	(21.2	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	85.60	$	72.97	$	12.63		17.3	%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	44.31	$	48.66	$	(4.35	)	(8.9	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.97		8.10		(2.13		)	(26.3	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	4.90		4.50		0.40			8.9	%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.56		7.00		(1.44		)	(20.6	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	7.90		9.51		(1.61		)	(16.9	)%
Total Production Costs Per Low Vol Met Ton Produced	$	68.64	$	77.77	$	(9.13	)	(11.7	)%

Ending Inventory Costs Per Low Vol Met Ton	$	64.76	$	69.84	$	(5.08	)	(7.3	)%

Total Costs Per Low Vol Met Ton Sold	$	70.46	$	79.80	$	(9.34	)	(11.7	)%
Margin Per Low Vol Met Ton Sold	$	27.08	$	43.91	$	(16.83	)	(38.3	)%

Low volatile metallurgical coal revenue was $111 million for the three months ended June 30, 2013 compared to $121 million for the three months ended June 30, 2012. The $10 million decrease was attributable to a $26.17 per ton lower average sales price and was partially offset by a 0.1 million increase in tons sold. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the weakening in global metallurgical coal demand. For the 2013 period, 0.8 million tons of low volatile metallurgical coal were priced on the export market at an average price of $89.02 per ton compared to 0.8 million tons at an average price of $107.72 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal was $80 million for the three months ended June 30, 2013, or $2 million higher than the $78 million for the three months ended June 30, 2012. Total cost of goods sold for low volatile metallurgical coal was $70.46 per ton in the three months ended June 30, 2013 compared to $79.80 per ton in the three months ended June 30, 2012. The decrease in cost of goods sold per low volatile metallurgical ton was due to the following items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Direct operating costs related to the low volatile metallurgical coal segment were $53 million in the three months ended June 30, 2013 compared to $56 million in the three months ended June 30, 2012. Direct operating costs improved primarily due to a five-day work schedule being implemented in the 2013 period at the Buchanan Mine and due to a decrease in contract mining fees resulting from the idling of the Amonate Complex in September 2012. Direct operating costs were $44.31 per ton produced in the current period compared to $48.66 per ton produced in the prior period. Low volatile metallurgical coal production was 1.2 million tons in the three months ended June 30, 2013 compared to 1.1 million tons in the three months ended June 30, 2012.

Royalties and production taxes were $7 million, or improved $2 million in the current period, compared to $9 million in the prior period. Unit costs also improved $2.13 per low volatile metallurgical ton produced to $5.97 per ton produced in the current period compared to $8.10 per ton produced in the prior period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes. These decreases were related to lower average sales prices.

operations for low volatile metallurgical coal were $4.90 per ton produced in the current period compared to $4.50 per ton produced in the prior period. Changes in the average direct service to operations cost per ton for low volatile metallurgical coal produced were primarily related to an increase in water treatment cost.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the low volatile metallurgical coal segment were $6 million for the three months ended June 30, 2013 compared to $8 million for the three months ended June 30, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan that occurred on June 30, 2012. This, coupled with the increase in volumes, resulted in an improvement on the unit costs of $1.44 in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $9 million for the three months ended June 30, 2013 compared to $11 million for the three months ended June 30, 2012. Unit costs per low volatile metallurgical tons produced were lower in the three months ended June 30, 2013 compared to the three months ended June 30, 2012 primarily due to the Amonate Complex being idled in September 2012 and the Buchanan reverse osmosis plant being temporarily idled in April and May 2013.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in a decrease of $1 million to cost of goods sold in the three months ended June 30, 2013 and an increase of $10 million to cost of goods sold in the three months ended June 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at June 30, 2013 compared to 0.3 million tons at June 30, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $87 million for the three months ended June 30, 2013 compared to earnings before income tax of $61 million for the three months ended June 30, 2012. 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.

Other coal segment produced coal sales includes revenue from the sale of less than 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the three months ended June 30, 2012. No coal was recovered during the reclamation process at idled facilities for the three months ended June 30, 2013. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.

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 June 30, 2013 compared to $3 million for the three months ended June 30, 2012.

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 June 30, 2013 compared to $49 million for the three months ended June 30, 2012. The $39 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $46 million for the three months ended June 30, 2013 compared to $184 million for the three months ended June 30, 2012. The change is due to the following items:

•

Gain on sale of assets attributable to the Other Coal segment were $26 million in the three months ended June 30, 2013 compared to $163 million in the three months ended June 30, 2012. The decrease of $137 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as the coal lands and surface rights in southern West Virginia that resulted in income of $11 million. This is offset, in part, by the 2013 sale of Potomac coal reserves that resulted in income of $25 million. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of

these sales. The remaining change was related to various transactions that occurred throughout both periods, none of which were individually material.


•	Equity in earnings of affiliates increased $6 million due to higher earnings from our equity affiliates.


•	The remaining $7 million decrease is due to various items, none of which are individually significant.

Other coal segment total costs were $148 million for the three months ended June 30, 2013 compared to $177 million for the three months ended June 30, 2012. The decrease of $29 million was primarily due to the following items:



	For the Three Months Ended June 30,
	2013		2012		Variance
Blacksville No. 2 Mine Fire	$	23	$	—	$	23
Purchased Coal	10		7		3
Stock-based compensation	8		7		1
Closed and idle mines	38		50		(12		)
Freight expense	10		49		(39		)
Other	59		64		(5		)
Total Other Coal Segment Costs	$	148	$	177	$	(29	)


•	The Blacksville No. 2 Mine fire expense was due to a fire that occurred on March 12, 2013. The mine resumed production on May 20, 2013. Insurance recovery is uncertain at this time and the impact of any potential recovery has not been reflected in the three months ended June 30, 2013.


•	Purchased coal costs increased due to higher amounts of coal that needed to be purchased to fulfill various contracts.

•

Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense and accelerated non-cash amortization for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program. The new program replaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.

•

Closed and idle mine costs decreased approximately $12 million for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. There was a $24 million decrease in asset retirement obligations. This was primarily due to an increase in the reclamation liability at the Fola Mining Complex in the June 2012 period due to new regulatory requirements, and water and selenium treatment estimates. The decrease was offset, in part, by an increase of $7 million due to the idling of the Fola Mining Complex in August 2012, and an increase of $2 million due to the idling of the Amonate Complex in September 2012. The remaining increase of $3 million was due to other changes in the operational status of various other mines, between idled and operating 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 decreased shipments under contracts which CONSOL Energy contractually provides transportation services.


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

TOTAL GAS SEGMENT ANALYSIS for the three months ended June 30, 2013 compared to the three months ended June 30, 2012:

The gas segment had a $5 million loss before income tax in the three months ended June 30, 2013 compared to earnings before income tax of $1 million in the three months ended June 30, 2012.



	For the Three Months Ended													Difference to Three Months Ended
	June 30, 2013													June 30, 2012
	CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	88	$	34		$	47	$	3		$	172		$	—		$	—		$	23	$	1		$	24
Related Party	1		—			—		—			1			—			—			—		—			—
Total Outside Sales	89		34			47		3			173			—			—			23		1			24
Gas Royalty Interest	—		—			—		17			17			—			—			—		7			7
Purchased Gas	—		—			—		1			1			—			—			—		1			1
Other Income	—		—			—		11			11			—			—			—		(7		)	(7		)
Total Revenue and Other Income	89		34			47		32			202			—			—			23		2			25
Lifting	10		10			5		1			26			(1		)	(1		)	3		1			2
Ad Valorem, Severance, and Other Taxes	3		3			1		—			7			1			1			—		—			2
Gathering	29		9			10		1			49			3			4			5		—			12
Gas Direct Administrative, Selling & Other	2		2			7		1			12			(2		)	(2		)	5		(1		)	—
Depreciation, Depletion and Amortization	23		15			12		2			52			1			1			3		—			5
General & Administration	—		—			—		12			12			—			—			—		3			3
Gas Royalty Interest	—		—			—		14			14			—			—			—		7			7
Purchased Gas	—		—			—		1			1			—			—			—		—			—
Exploration and Other Costs	—		—			—		10			10			—			—			—		(6		)	(6		)
Other Corporate Expenses	—		—			—		22			22			—			—			—		5			5
Interest Expense	—		—			—		2			2			—			—			—		1			1
Total Cost	67		39			35		66			207			2			3			16		10			31
Earnings Before Income Tax	$	22	$	(5	)	$	12	$	(34	)	$	(5	)	$	(2	)	$	(3	)	$	7	$	(8	)	$	(6	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $22 million to the total Company earnings before income tax for the three months ended June 30, 2013 compared to $24 million for the three months ended June 30, 2012.



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	20.8		22.3		(1.5		)	(6.7	)%
Average CBM sales price per thousand cubic feet sold	$	4.26	$	3.96	$	0.30		7.6	%
Average CBM lifting costs per thousand cubic feet sold	0.48		0.45		0.03			6.7	%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.13		0.11		0.02			18.2	%
Average CBM gathering costs per thousand cubic feet sold	1.40		1.17		0.23			19.7	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.10		0.18		(0.08		)	(44.4	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.09		0.96		0.13			13.5	%
Total Average CBM costs per thousand cubic feet sold	3.20		2.87		0.33			11.5	%
Average Margin for CBM	$	1.06	$	1.09	$	(0.03	)	(2.8	)%

CBM sales revenues were $89 million in the three months ended June 30, 2013 and 2012. The 6.7% decrease in volumes sold was offset by a 7.6% increase in average sales price per thousand cubic feet sold. The increase in CBM average sales price was the result of higher average market prices offset by various gas swap transactions that matured in each period. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 11.6 billion cubic feet of our produced CBM gas sales volumes for the three months ended June 30, 2013 at an average price of $4.58 per thousand cubic feet. For the three months ended June 30, 2012, these financial hedges represented 10.9 billion cubic feet at an average price of $5.33 per thousand cubic feet. CBM sales volumes decreased 1.5 billion cubic feet for the three months ended June 30, 2013 compared to the 2012 period primarily due to normal well declines without a corresponding increase in wells drilled. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage.

Total costs for the CBM segment were $67 million for the three months ended June 30, 2013 compared to $65 million for the three months ended June 30, 2012. The increase in total costs for the CBM segment are due to the following items:

•CBM lifting costs were $10 million for the three months ended June 30, 2013 compared to $11 million for the three months ended June 30, 2012. The decrease in total dollars and the $0.03 per thousand cubic feet increase in average lifting unit costs are both directly related to the decreased sales volumes as discussed above.

•CBM ad valorem, severance and other taxes were $3 million for the three months ended June 30, 2013 compared to $2 million for the three months ended June 30, 2012. The $1 million increase in total dollars was primarily due to increased severance tax expense due to higher average gas sales prices. The $0.02 per thousand cubic feet increase in unit costs is primarily due to the higher average gas sales prices and decrease in sales volumes.

•CBM gathering costs were $29 million for the three months ended June 30, 2013 compared to $26 million for the three months ended June 30, 2012. The $0.23 per thousand cubic feet increase in average CBM gathering unit costs are related to increased power costs due to higher utility rates, increased pipeline maintenance, increased road maintenance and lower volumes sold in the period-to-period comparison.

•CBM direct administrative, selling & other costs for the CBM segment were $2 million for the three months ended June 30, 2013 compared to $4 million for the three months ended June 30, 2012. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The decrease in direct administrative, selling & other costs was primarily due to reduced direct administrative labor and CBM volumes representing a smaller proportion of total natural gas volumes sold. Improvements in unit costs were offset, in part, by the reduction in volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $23 million for the three months ended June 30, 2013 compared to $22 million for the three months ended June 30, 2012. There was approximately $16 million, or $0.76 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2013. The production portion of depreciation, depletion and amortization was $15 million, or $0.67 per unit-of-production in the three months ended June 30, 2012. There was approximately $7 million, or $0.33 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended June 30, 2013. The non-production related depreciation, depletion and amortization was $7 million, or $0.29 per thousand cubic feet for the three months ended June 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $5 million for the three months ended June 30, 2013 compared to a loss before income tax of $2 million for the three months ended June 30, 2012.



	For the Three Months Ended June 30,
	2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	6.7			7.2			(0.5		)	(6.9	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	5.00		$	4.74		$	0.26		5.5	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.46			1.46			—			—	%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.43			0.30			0.13			43.3	%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.35			0.77			0.58			75.3	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.34			0.53			(0.19		)	(35.8	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.25			2.01			0.24			11.9	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.83			5.07			0.76			15.0	%
Average Margin for Shallow Oil and Gas	$	(0.83	)	$	(0.33	)	$	(0.50	)	(151.5	)%

Shallow Oil and Gas sales revenues were $34 million for both the three months ended June 30, 2013 and 2012. The 6.9% decrease in volumes sold was offset, in part, by a 5.5% increase in average sales price. The increase in shallow oil and gas average sales price is the result of higher average market prices offset by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 3.6 billion cubic feet of our produced shallow oil and gas sales volumes for the three months ended June 30, 2013 at an average price of $5.21 per thousand cubic feet. For the three months ended June 30, 2012, these financial hedges represented 5.4 billion cubic feet at an average price of $5.25 per thousand cubic feet.

Total costs for the shallow oil and gas segment were $39 million for the three months ended June 30, 2013 compared to $36 million for the three months ended June 30, 2012. The increase in total costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $10 million for the three months ended June 30, 2013 compared to $11 million for the three months ended June 30, 2012. The $1 million decrease to total costs is due to lower road maintenance, lower salt water disposal costs and lower contract services in the current period, offset, in part, by an increase in accretion expense on the well plugging liability. The average unit costs remained consistent in the period-to-period comparison due to the decrease in sales volumes.

•Shallow Oil and Gas ad valorem, severance and other taxes were $3 million for the three months ended June 30, 2013 and $2 million for the three months ended June 30, 2012. The $1 million increase in total costs was primarily due to higher average sales prices during the current period. The $0.13 per thousand cubic feet increase in average unit costs is primarily due to the higher average sales prices and decreased sales volumes.

•Shallow Oil and Gas gathering costs were $9 million for the three months ended June 30, 2013 compared to $5 million for the three months ended June 30, 2012. Gathering costs increased $4 million primarily due to increased firm transportation costs and higher compressor repair and maintenance costs in the period-to-period comparison.

•Shallow Oil and Gas direct administrative, selling & other costs were $2 million for the three months ended June 30, 2013 compared to $4 million for the three months ended June 30, 2012. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The $2 million decrease in the period-to-period comparison is due to reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes sold. The decrease in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization costs were $15 million for the three months ended June 30, 2013 compared to $14 million for the three months ended June 30, 2012. There was approximately $13 million, or $1.98 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2013. There was approximately $12 million, or $1.77 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2012. There was approximately $2 million, or $0.27 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2013. There was $2 million, or $0.24 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the three months ended June 30, 2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $12 million to the total Company earnings before income tax for the three months ended June 30, 2013 compared to $5 million for the three months ended June 30, 2012.



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	10.4		7.2		3.2			44.4	%
Average Marcellus sales price per thousand cubic feet sold	$	4.49	$	3.28	$	1.21		36.9	%
Average Marcellus lifting costs per thousand cubic feet sold	0.44		0.28		0.16			57.1	%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.15		0.13		0.02			15.4	%
Average Marcellus gathering costs per thousand cubic feet sold	0.95		0.64		0.31			48.4	%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.63		0.27		0.36			133.3	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.19		1.29		(0.10		)	(7.8	)%
Total Average Marcellus costs per thousand cubic feet sold	3.36		2.61		0.75			28.7	%
Average Margin for Marcellus	$	1.13	$	0.67	$	0.46		68.7	%

The Marcellus segment sales revenues were $47 million for the three months ended June 30, 2013 compared to $24 million for the three months ended June 30, 2012. The $23 million increase is primarily due to a 44.4% increase in volumes sold, and a 36.9% increase in average sales prices in the period-to-period comparison. The increase in Marcellus average sales price was the result of the improvement in general market prices and sales of natural gas liquids and condensate, offset by various gas swap transactions that matured in the three months ended June 30, 2013. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 4.5 billion cubic feet of our produced Marcellus gas sales volumes for the three months ended June 30, 2013 at an average price of $4.74 per thousand cubic feet. For the three months ended June 30, 2012, these financial hedges represented 2.8 billion cubic feet at an average price of $4.95 per thousand cubic feet. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program.

Total costs for the Marcellus segment were $35 million for the three months ended June 30, 2013 compared to $19 million for the three months ended June 30, 2012. The increase in total costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $5 million for the three months ended June 30, 2013 compared to $2 million for the three months ended June 30, 2012. The increase primarily relates to increased road maintenance costs, increased salt water disposal costs, and increased accretion expense on the well plugging liability.

•Marcellus ad valorem, severance and other taxes were $1 million for the three months ended June 30, 2013 and 2012. The increase in average unit costs was primarily due to an increase in severance tax expense caused by higher average gas sales prices during the current period.

•Marcellus gathering costs were $10 million for the three months ended June 30, 2013 compared to $5 million for the three months ended June 30, 2012. Average gathering costs increased $0.31 per unit primarily due to increased firm transportation costs, and increased processing fees associated with natural gas liquids.

•Marcellus direct administrative, selling & other costs were $7 million for the three months ended June 30, 2013 compared to $2 million for the three months ended June 30, 2012. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of total natural gas volumes sold. The impact on average unit costs from the increase in direct administrative costs was partially offset by higher volumes sold.

•Depreciation, depletion and amortization costs were $12 million for the three months ended June 30, 2013 compared to $9 million for the three months ended June 30, 2012. There was approximately $12 million, or $1.18 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the three months ended June 30, 2013. There was approximately $8 million, or $1.14 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the three months ended June 30, 2012. There was less than $1 million, or $0.01 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the three months ended June 30, 2013. There was $1 million, or $0.15 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the three months ended June 30, 2012.

OTHER GAS SEGMENT

The other gas segment includes activity not assigned to the CBM, Shallow Oil and Gas or Marcellus 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 gas segment.

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee and the Utica Shale in Ohio. Revenue from these operations were approximately $3 million for the three months ended June 30, 2013 and $2 million for the three months ended June 30, 2012. Total costs related to these other sales were $5 million for the three months ended June 30, 2013 and June 30, 2012. A per unit analysis of the other operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the 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 gas segment. Royalty interest gas sales revenue was $17 million for the three months ended June 30, 2013 compared to $10 million for the three months ended June 30, 2012. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.9		4.2		(0.3		)	(7.1	)%
Average Sales Price Per thousand cubic feet	$	4.31	$	2.26	$	2.05		90.7	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $1 million for the three months ended June 30, 2013 and less than $1 million for the three months ended June 30, 2012.



	For the Three Months Ended June 30,
	2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.4		0.3		0.1		33.3	%
Average Sales Price Per thousand cubic feet	$	3.96	$	2.39	$	1.57	65.7	%

Other income was $11 million for the three months ended June 30, 2013 compared to $18 million for the three months ended June 30, 2012. The $7 million change was primarily due to the following items:


•	Interest income related to the notes receivable from the Noble joint venture transaction decreased $4 million due to the payment of the first note in September 2012.


•	Gains on dispositions of non-core acreage and equipment decreased $2 million due to various transactions that occurred throughout both periods, none of which are individually material.


•	There was a decrease of $1 million in various other transactions, none of which are individually material.

General and administrative costs are allocated to the total gas segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $12 million for the three months ended June 30, 2013 compared to $9 million for the three months ended June 30, 2012. 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 gas segment. Royalty interest gas costs were $14 million for the three months ended June 30, 2013 compared to $7 million for the three months ended June 30, 2012. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	3.9		4.2		(0.3		)	(7.1	)%
Average Cost Per thousand cubic feet sold	$	3.43	$	1.69	$	1.74		103.0	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. The higher average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $1 million for the three months ended June 30, 2013 and 2012.



	For the Three Months Ended June 30,
	2013		2012		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.4		0.3		0.1		33.3	%
Average Cost Per thousand cubic feet sold	$	2.99	$	2.19	$	0.80	36.5	%

Exploration and other costs were $10 million for the three months ended June 30, 2013 compared to $16 million for the three months ended June 30, 2012. The $6 million decrease is due to the following items:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Marcellus Title Defects	$	2	$	—	$	2		100	%
Exploration	5		5		—			—	%
Lease Expiration Costs	3		11		(8		)	(72.7	)%
Total Exploration and Other Costs	$	10	$	16	$	(6	)	(37.5	)%


•	As part of the title defect process the company is working through with its joint venture partner, Noble Energy, CONSOL Energy conceded title defects on acreage which had a book value to CONSOL Energy of $2 million.


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


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $8 million decrease is due to CONSOL Energy allowing fewer leases to expire in the current period when compared with the prior period.

Other corporate expenses were $22 million for the three months ended June 30, 2013 compared to $17 million for the three months ended June 30, 2012. The $5 million increase in the period-to-period comparison was made up of the following items:



	For the Three Months Ended June 30,
	2013		2012		Variance			Percent Change
Unutilized firm transportation	$	9	$	3	$	6		200	%
Stock-based compensation	5		4		1			25	%
Bank fees	2		2		—			—	%
Short term incentive compensation	4		7		(3		)	(42.9	)%
Other	2		1		1			100	%
Total Other Corporate Expenses	$	22	$	17	$	5		29.4	%


•	Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase. The $6 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

•


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


•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense was lower for the 2013 period compared to the 2012 period due to the projected lower payouts.


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

Interest expense related to the gas segment was $2 million for the three months ended June 30, 2013 compared to $1 million for the three months ended June 30, 2012. Interest was incurred on the CNX Gas revolving credit facility and a capital lease. The $1 million increase was primarily due to higher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the three months ended June 30, 2013 compared to the three months ended June 30, 2012:

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 $58 million for the three months ended June 30, 2013 compared to a loss before income tax of $45 million for the three months ended June 30, 2012. The other segment also includes total Company income tax expense of $15 million for the three months ended June 30, 2013 compared to $59 million for the three months ended June 30, 2012.



	For the Three Months Ended June 30,
	2013			2012			Variance			Percent Change
Sales—Outside	$	83		$	96		$	(13	)	(13.5	)%
Other Income	3			3			—			—	%
Total Revenue	86			99			(13		)	(13.1	)%
Cost of Goods Sold and Other Charges	81			81			—			—	%
Depreciation, Depletion & Amortization	7			6			1			16.7	%
Taxes Other Than Income Tax	3			2			1			50.0	%
Interest Expense	53			55			(2		)	(3.6	)%
Total Costs	144			144			—			—	%
Loss Before Income Tax	(58		)	(45		)	(13		)	28.9	%
Income Tax	15			59			(44		)	(74.6	)%
Net Loss	$	(73	)	$	(104	)	$	31		29.8	%

Industrial supplies:

Outside Sales from industrial supplies was $54 million for the three months ended June 30, 2013 compared to $64 million for the three months ended June 30, 2012. The decrease of $10 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $53 million for the three months ended June 30, 2013 compared to $62 million for the three months ended June 30, 2012. The decrease of $9 million was primarily related to lower sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Outside Sales from transportation operations was $29 million for the three months ended June 30, 2013 compared to $32 million for the three months ended June 30, 2012. The decrease of $3 million was primarily attributable to decreased thru-put at the CNX Marine Terminal offset, in part, by higher per ton thru-put rates.

Total costs related to the transportation operations were $25 million for the three months ended June 30, 2013 compared to $21 million for the three months ended June 30, 2012. The increase of $4 million was due to various items in both periods, none of which were individually material.

Miscellaneous other:

Additional other income remained consistent at $3 million for the three months ended June 30, 2013 and June 30, 2012.

Other corporate costs were $66 million for the three months ended June 30, 2013 compared to $61 million for the three months ended June 30, 2012. Other corporate costs increased due to the following items:



	For the Three Months Ended June 30,
	2013		2012		Variance
Pension settlement	$	5	$	—	$	5
Bank fees	4		3		1
Interest expense	53		56		(3		)
Other	4		2		2
	$	66	$	61	$	5


•	Pension settlement adjustment is the acceleration of unrecognized actuarial losses due to lump sum payments from the pension plan exceeding the annual projected service and interest costs of the plan.


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


•	Interest expense decreased $3 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.


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

Income Taxes:

The effective income tax rate was 808.3% for the three months ended June 30, 2013 compared to 27.8% for the three months ended June 30, 2012. The effective rates for the three months ended June 30, 2013 and 2012 were calculated using the annual effective rate projection on recurring earnings and include tax liabilities related to certain discrete transactions. The relationship between pre-tax earnings and percentage depletion impacts the effective tax rate. See Note 5 - Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Three Months Ended June 30,
	2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	2		$	212		$	(210	)	(99.2	)%
Income Tax Expense	$	15		$	59		$	(44	)	(74.6	)%
Effective Income Tax Rate	808.3		%	27.8		%	780.5		%

Results of Operations

Six Months Ended June 30, 2013 Compared with Six Months Ended June 30, 2012

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported a net loss attributable to CONSOL Energy shareholders of $14 million, or $(0.06) per diluted share, for the six months ended June 30, 2013. Net income attributable to CONSOL Energy shareholders was $250 million, or $1.09 per diluted share, for the six months ended June 30, 2012.

The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed $158 million of earnings before income tax for the six months ended June 30, 2013 compared to $419 million for the six months ended June 30, 2012. The total coal division sold 29.0 million tons of coal produced from CONSOL Energy mines for the six months ended June 30, 2013 and 29.6 million tons of coal produced from CONSOL Energy mines for the six months ended June 30, 2012.

The average sales price and total costs per ton for all active coal operations were as follows:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Average Sales Price per ton sold	$	63.17	$	67.37	$	(4.20	)	(6.2	)%
Average Cost of Goods Sold per ton	51.25		53.36		(2.11		)	(4.0	)%
Margin per ton sold	$	11.92	$	14.01	$	(2.09	)	(14.9	)%

The lower average sales price per ton sold reflects a decrease in the global metallurgical and thermal coal markets. The coal division priced 5.0 million tons on the export market at an average sales price of $72.74 for the six months ended June 30, 2013 compared to 6.7 million tons at an average price of $75.85 per ton for the six months ended June 30, 2012. All other tons were sold on the domestic market.

Changes in the average cost of goods sold per ton were primarily related to the following items:

•

Direct operating costs improved primarily due to a decrease in all direct operating costs at the Blacksville No. 2 Mine which is the result of the mine being idled until May 20th due to the fire, as previously discussed. In March and April 2012, the Blacksville No. 2 Mine ran the continuous miners and worked on various projects, but the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.


•	Costs were improved due to a reduction in gas well plugging costs at the Shoemaker Mine and due to the shutdown of the Fola Mining Complex in August 2012.


•	Average direct operating costs were impaired due to CONSOL Energy entering into several new leases for various types of mining equipment at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.


•	In March and April 2012, the Buchanan Mine ran the continuous miners and worked on various projects, but the longwall was idled resulting in lower 2012 unit costs. This did not occur in the 2013 period.


•	Direct services to operations are improved primarily due to a reduction in subsidence expenses related to the timing and nature of properties and streams undermined as well as a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.


•	Depreciation, depletion and amortization was improved primarily due to lower production at Blacksville No. 2 Mine related to the mine being shut down due to the fire, the shutdown of operations at the Fola Mining Complex and the timing of assets going in service or being fully depreciated.

The total gas division includes CBM, Shallow Oil and Gas, Marcellus and other gas. The total gas division had a $5 million loss before income tax for the six months ended June 30, 2013 compared to $13 million of earnings before income tax for the six months ended June 30, 2012. Total gas production was 77.8 billion cubic feet for the six months ended June 30, 2013 compared to 75.0 billion cubic feet for the six months ended June 30, 2012. Total gas volumes increased primarily as a result of the on-going Marcellus drilling program.

The average sales price and total costs for all active gas operations were as follows:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	4.38	$	4.12	$	0.26		6.3%
Average Costs per thousand cubic feet sold	3.65		3.36		0.29			8.6%
Margin per thousand cubic feet sold	$	0.73	$	0.76	$	(0.03	)	(3.9)%

Total gas division outside sales revenues were $341 million for the six months ended June 30, 2013 compared to $309 million for the six months ended June 30, 2012. The increase was primarily due to the 3.7% increase in volumes sold, along with a 6.3% increase in average price per thousand cubic feet sold. The increase in average sales price is the result of the increase in general market prices and sales of natural gas liquids, partially offset by various gas swap transactions that occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 36.3 billion cubic feet of our produced gas sales volumes for the six months ended June 30, 2013 at an average price of $4.75 per thousand cubic feet. These financial hedges represented 38.2 billion cubic feet of our produced gas sales volumes for the six months ended June 30, 2012 at an average price of $5.25 per thousand cubic feet.

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


•	Gathering costs increased in the period-to-period comparison due to higher firm transportation costs and increased processing fees associated with natural gas liquids.


•	Lifting costs increased due to increased accretion expense on the well plugging liability as well as increased salt water disposal costs. This impairment was partially offset by improvements related to decreased expenditures for contract services, environmental compliance and safety costs and well services costs in the current period.


•	Higher units-of-production depreciation, depletion and amortization rates for producing properties.


•	These increases were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling program. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

The other segment includes industrial supplies activity, terminal, river and dock service activity, income taxes and other business activities not assigned to the coal or gas segment.

General and administrative costs are allocated between divisions (Coal, Gas and Other) based primarily on percentage of total revenue and percentage of total projected capital expenditures. General and administrative costs are excluded from the coal and gas unit costs above. Total general and administrative costs were made up of the following items:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Consulting and professional services	$	15	$	12	$	3		25.0	%
Contributions	7		5		2			40.0	%
Advertising and promotion	4		4		—			—	%
Employee wages and related expenses	27		32		(5		)	(15.6	)%
Miscellaneous	14		13		1			7.7	%
Total Company General and Administrative Expenses	$	67	$	66	$	1		1.5	%

Total Company General and Administrative Expenses changed due to the following:


•	Consulting and professional services increased $3 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which are individually significant.


•	Contributions increased $2 million related to various transactions that occurred throughout both periods, none of which are individually material.


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


•	Employee wages and related expenses decreased $5 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.


•	Miscellaneous general and administrative expenses increased slightly in the period-to-period comparison due to various transactions, none of which were individually material.

Total Company long-term liabilities, 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 expense related to our actuarial liabilities was $155 million for the six months ended June 30, 2013 compared to $131 million for the six months ended June 30, 2012. The increase of $24 million for total CONSOL Energy expense was primarily due to required pension settlement accounting of $32 million related to lump sum distributions made for the 2013 plan year exceeding 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 coal or gas. This was offset, in part, due to a modification to the benefit plan for salaried employees and an increase in the discount rate assumptions used to calculate expense for benefit plans at the measurement date, which is December 31. See Note 3 - Components of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs and Note 4 - Components of Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Unaudited Consolidated Financial Statements for additional detail of the total Company expense decrease.

TOTAL COAL SEGMENT ANALYSIS for the six months ended June 30, 2013 compared to the six months ended June 30, 2012:

The coal segment contributed $158 million of earnings before income tax in the six months ended June 30, 2013 compared to $419 million in the six months ended June 30, 2012. Variances by the individual coal segments are discussed below.



	For the Six Months Ended														Difference to Six Months Ended
	June 30, 2013														June 30, 2012
	Thermal Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal			Thermal Coal			High Vol Met Coal			Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	1,459		$	116	$	258		$	—		$	1,833		$	(101	)	$	(16	)	$	(35	)	$	(6	)	$	(158	)
Purchased Coal	—			—		—			11			11			—			—			—			3			3
Total Outside Sales	1,459			116		258			11			1,844			(101		)	(16		)	(35		)	(3		)	(155		)
Freight Revenue	—			—		—			24			24			—			—			—			(75		)	(75		)
Other Income	1			2		—			61			64			1			(4		)	—			(150		)	(153		)
Total Revenue and Other Income	1,460			118		258			96			1,932			(100		)	(20		)	(35		)	(228		)	(383		)
Costs and Expenses:
Beginning inventory costs	58			—		21			—			79			(32		)	—			5			—			(27		)
Total direct operating costs	760			57		102			102			1,021			(49		)	(6		)	(13		)	39			(29		)
Total royalty/production taxes	102			3		14			1			120			(5		)	(4		)	(4		)	(1		)	(14		)
Total direct services to operations	117			10		12			124			263			(35		)	(3		)	1			(21		)	(58		)
Total retirement and disability	88			6		13			8			115			(4		)	—			(3		)	1			(6		)
Depreciation, depletion and amortization	145			11		20			27			203			(13		)	(3		)	(1		)	19			2
Ending inventory costs	(42		)	—		(9		)	—			(51		)	68			—			17			—			85
Total Costs and Expenses	1,228			87		173			262			1,750			(70		)	(16		)	2			37			(47		)
Freight Expense	—			—		—			24			24			—			—			—			(75		)	(75		)
Total Costs	1,228			87		173			286			1,774			(70		)	(16		)	2			(38		)	(122		)
Earnings (Loss) Before Income Taxes	$	232		$	31	$	85		$	(190	)	$	158		$	(30	)	$	(4	)	$	(37	)	$	(190	)	$	(261	)

THERMAL COAL SEGMENT

The thermal coal segment contributed $232 million to total Company earnings before income tax for the six months ended June 30, 2013 and $262 million for the six months ended June 30, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced Thermal Tons Sold (in millions)	24.6		25.3		(0.7		)	(2.8	)%
Average Sales Price Per Thermal Ton Sold	$	59.19	$	61.66	$	(2.47	)	(4.0	)%

Beginning Inventory Costs Per Thermal Ton	$	50.92	$	58.32	$	(7.40	)	(12.7	)%

Total Direct Operating Costs Per Thermal Ton Produced	$	31.30	$	31.45	$	(0.15	)	(0.5	)%
Total Royalty/Production Taxes Per Thermal Ton Produced	4.21		4.16		0.05			1.2	%
Total Direct Services to Operations Per Thermal Ton Produced	4.82		5.90		(1.08		)	(18.3	)%
Total Retirement and Disability Per Thermal Ton Produced	3.63		3.58		0.05			1.4	%
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced	5.96		6.12		(0.16		)	(2.6	)%
Total Production Costs Per Thermal Ton Produced	$	49.92	$	51.21	$	(1.29	)	(2.5	)%

Ending Inventory Costs Per Thermal Ton	$	55.36	$	56.03	$	(0.67	)	(1.2	)%

Total Costs Per Thermal Ton Sold	$	49.81	$	51.32	$	(1.51	)	(2.9	)%
Average Margin Per Thermal Ton Sold	$	9.38	$	10.34	$	(0.96	)	(9.3	)%

Thermal coal revenue was $1,460 million for the six months ended June 30, 2013 compared to $1,560 million for the six months ended June 30, 2012. The $100 million decrease was attributable to a $2.47 per ton lower average sales price and 0.7 million reduction in tons sold. The lower average thermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1, 2013. Also, 1.5 million tons of thermal coal were priced on the export market at an average sales price of $61.67 per ton for the six months ended June 30, 2013 compared to 3.3 million tons at an average price of $57.12 per ton for the six months ended June 30, 2012.

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. Total cost of goods sold for thermal coal was $1,228 million for the six months ended June 30, 2013, or $70 million lower than the $1,298 million for the six months ended June 30, 2012. Total cost of goods sold for thermal coal was $49.81 per ton in the six months ended June 30, 2013 compared to $51.32 per ton in the six months ended June 30, 2012. The decrease in costs of goods sold per thermal ton was due to the items described below.


•	The Blacksville No. 2 mine was idled on March 12, 2013 and resumed production on May 20, 2013 due to the fire that was previously discussed, this resulted in a reduction in all direct operating costs.


•	In March and April 2012, the Blacksville No. 2 Mine ran the continuous miners and worked on various projects, but the longwall was idled resulting in higher 2012 unit costs. This did not occur in 2013.


•	The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.


•	In 2013, CONSOL Energy entered into several new leases for various mining equipment, which resulted in higher cost per ton produced in the period-to-period comparison.

Royalties and production taxes decreased $5 million to $102 million in the current period. Average cost per thermal ton produced increased $0.05 per ton to $4.21 per ton sold, due to lower production volumes and lower average sales prices which is the basis for most production taxes.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The cost of these support services was $117 million in the current period compared to $152 million in the prior period. Direct services to the operations were $4.82 per ton produced in the current period compared to $5.90 per ton produced in the prior period. Changes in the average direct service to operations cost per thermal ton produced were primarily related to the following items:


•	Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison.


•	Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, that was discussed previously.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the thermal coal segment were $88 million for the six months ended June 30, 2013 compared to $92 million for the six months ended June 30, 2012. The decrease in the thermal coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan that occurred June 30, 2012. Average cost per thermal ton produced increased $0.05 per ton to $3.63 per ton sold due to lower production volumes.

Depreciation, depletion and amortization for the thermal coal segment was $145 million for the six months ended June 30, 2013 compared to $158 million for the six months ended June 30, 2012. Unit costs per thermal ton produced were lower in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 due to the idling of the Fola Mining Complex in August 2012.

Changes in thermal coal inventory volumes and carrying value resulted in $16 million of cost of goods sold in the six months ended June 30, 2013 compared to a $20 million reduction of cost of goods sold in the six months ended June 30, 2012. Thermal coal inventory was 0.8 million tons at June 30, 2013 compared to 2.0 million tons at June 30, 2012.

HIGH VOL METALLURGICAL COAL SEGMENT

The high volatile metallurgical coal segment contributed $31 million to total Company earnings before income tax for the six months ended June 30, 2013 compared to $35 million for the six months ended June 30, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for these periods are as follows:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced High Vol Met Tons Sold (in millions)	1.8		2.2		(0.4		)	(18.2	)%
Average Sales Price Per High Vol Met Ton Sold	$	64.57	$	60.95	$	3.62		5.9	%

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

Total Direct Operating Costs Per High Vol Met Ton Produced	$	31.87	$	29.03	$	2.84		9.8	%
Total Royalty/Production Taxes Per High Vol Met Ton Produced	1.44		3.17		(1.73		)	(54.6	)%
Total Direct Services to Operations Per High Vol Met Ton Produced	5.86		6.14		(0.28		)	(4.6	)%
Total Retirement and Disability Per High Vol Met Ton Produced	3.32		2.91		0.41			14.1	%
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced	5.93		6.26		(0.33		)	(5.3	)%
Total Production Costs Per High Vol Met Ton Produced	$	48.42	$	47.51	$	0.91		1.9	%

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

Total Costs Per High Vol Met Ton Sold	$	48.42	$	47.51	$	0.91		1.9	%
Margin Per High Vol Met Ton Sold	$	16.15	$	13.44	$	2.71		20.2	%

High volatile metallurgical coal revenue was $118 million for the six months ended June 30, 2013 compared to $138 million for the six months ended June 30, 2012. Average sales prices for high volatile metallurgical coal increased $3.62 per ton in a period-to-period comparison. CONSOL Energy priced 1.6 million tons of high volatile metallurgical coal in the export market at an average sales price of $62.21 per ton for the six months ended June 30, 2013 compared to 1.9 million tons at an average price of $58.15 per ton for the six months ended June 30, 2012. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for high volatile metallurgical coal was $87 million for the six months ended June 30, 2013, or $16 million lower than the $103 million for the six months ended June 30, 2012. Total cost of goods sold for high volatile metallurgical coal was $48.42 per ton in the six months ended June 30, 2013 compared to $47.51 per ton in the six months ended June 30, 2012. The increase in cost of goods sold per high volatile metallurgical ton was due to the items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Direct operating costs related to the high volatile metallurgical coal segment were $57 million in the six months ended June 30, 2013 compared to $63 million in the six months ended June 30, 2012. The reduction in total dollars was primarily due to a reduction in mine maintenance and supply expense as a result of the shutdown of the Fola Mining Complex in August 2012. Direct operating costs were $31.87 per ton produced in the current period compared to $29.03 per ton produced in the prior period. The increase in the average direct operating costs per high volatile metallurgical ton produced was primarily due to fewer tons produced. Fixed costs are allocated over less tons, resulting in higher unit costs.

Royalties and production taxes improved $4 million in the current period due primarily to the shutdown of the Fola Mining Complex in August 2012.

Direct services to operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance

costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for high volatile metallurgical coal were $10 million in the current period compared to $13 million in the prior period. Direct services to the operations for high volatile metallurgical coal were $5.86 per ton in the current period compared to $6.14 per ton in the prior period. Changes in the average direct services to operations cost per ton for high volatile metallurgical coal produced were primarily related to the following items:


•	Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison.


•	Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, that was discussed previously.

Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $11 million for the six months ended June 30, 2013 and $14 million for the six months ended June 30, 2012. Unit costs per high volatile ton produced were lower in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 due primarily to the shutdown of the Fola Mining Complex in August 2012.

There were no changes in volumes or carrying value of coal inventory in the six months ended June 30, 2013 and June 30, 2012. There was no high volatile metallurgical coal inventory at June 30, 2013 or June 30, 2012.

LOW VOL METALLURGICAL COAL SEGMENT

The low volatile metallurgical coal segment contributed $85 million to total Company earnings before income tax in the six months ended June 30, 2013 compared to $122 million in the six months ended June 30, 2012. The low volatile metallurgical coal revenue and cost components on a per ton basis for these periods are as follows:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Company Produced Low Vol Met Tons Sold (in millions)	2.6		2.0		0.6			30.0	%
Average Sales Price Per Low Vol Met Ton Sold	$	100.41	$	146.40	$	(45.99	)	(31.4	)%

Beginning Inventory Costs Per Low Vol Met Ton	$	86.38	$	67.60	$	18.78		27.8	%

Total Direct Operating Costs Per Low Vol Met Ton Produced	$	40.96	$	53.38	$	(12.42	)	(23.3	)%
Total Royalty/Production Taxes Per Low Vol Met Ton Produced	5.79		8.63		(2.84		)	(32.9	)%
Total Direct Services to Operations Per Low Vol Met Ton Produced	4.85		5.35		(0.50		)	(9.3	)%
Total Retirement and Disability Per Low Vol Met Ton Produced	5.37		7.62		(2.25		)	(29.5	)%
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced	8.10		9.65		(1.55		)	(16.1	)%
Total Production Costs Per Low Vol Met Ton Produced	$	65.07	$	84.63	$	(19.56	)	(23.1	)%

Ending Inventory Costs Per Low Vol Met Ton	$	64.76	$	69.84	$	(5.08	)	(7.3	)%

Total Costs Per Low Vol Met Ton Sold	$	67.10	$	85.43	$	(18.33	)	(21.5	)%
Margin Per Low Vol Met Ton Sold	$	33.31	$	60.97	$	(27.66	)	(45.4	)%

Low volatile metallurgical coal revenue was $258 million for the six months ended June 30, 2013 compared to $293 million for the six months ended June 30, 2012. The $35 million decrease was attributable to a $45.99 per ton lower average sales price. Average sales prices for low volatile metallurgical coal decreased in the period-to-period comparison due to the

weakening in global metallurgical coal demand. For the 2013 period, 2.0 million tons of low volatile metallurgical coal were priced on the export market at an average price of $89.53 per ton compared to 1.6 million tons at an average price of $136.32 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.

Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tons produced in the period. Total cost of goods sold for low volatile metallurgical coal was $173 million for the six months ended June 30, 2013, or $2 million higher than the $171 million for the six months ended June 30, 2012. Total cost of goods sold for low volatile metallurgical coal was $67.10 per ton in the six months ended June 30, 2013 compared to $85.43 per ton in the six months ended June 30, 2012. The decrease in cost of goods sold per low volatile metallurgical ton was due to the following items described below.

Direct operating costs are comprised of labor, supplies, maintenance, power and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Direct operating costs related to the low volatile metallurgical coal segment were $102 million in the six months ended June 30, 2013 compared to $115 million in the six months ended June 30, 2012. Direct operating costs improved primarily as the result of several cost saving initiatives at the Buchanan Mine, such as, slowing the pace of major maintenance projects, right sizing the workforce to fit the recently implemented five-day work schedule, and opening the Horn Mountain portal, which allowed employees to enter the mine much closer to the longwall face. The improvement was partially offset by lower direct operating costs in the 2012 period due to the Buchanan Mine longwall being temporarily idled in March and April. Direct operating costs were $40.96 per ton produced in the current period compared to $53.38 per ton produced in the prior period. Low volatile metallurgical coal production was 2.5 million tons in the six months ended June 30, 2013 compared to 2.1 million tons in the six months ended June 30, 2012.

Royalties and production taxes improved $4 million to $14 million in the current period compared to $18 million in the prior period. Unit costs also improved $2.84 per low volatile metallurgical ton produced to $5.79 per ton produced in the current period compared to $8.63 per ton produced in the prior period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes, primarily related to lower average sales prices.

Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct services are comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and water treatment costs. The costs of these support services for low volatile metallurgical coal were $12 million in the current and $11 million in the prior periods. Direct services to operations for low volatile metallurgical coal were $4.85 per ton produced in the current period compared to $5.35 per ton produced in the prior period. Changes in the average direct services to operations cost per ton for low volatile metallurgical coal produced were due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan and due to higher tons of coal produced in the period-to-period comparison.

Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-retirement benefits (OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities 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. The retirement and disability costs attributable to the low volatile metallurgical coal segment were $13 million for the six months ended June 30, 2013 compared to $16 million for the six months ended June 30, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs was primarily attributable to an increase in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan that occurred on June 30, 2012. This, coupled with the increase in volumes, resulted in an improvement on the unit costs of $2.25 in the period-to-period comparison.

Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $20 million for the six months ended June 30, 2013 compared to $21 million for the six months ended June 30, 2012. Unit costs per low volatile metallurgical tons produced were lower in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 primarily due to the Amonate Complex being idled in September 2012 and the Buchanan reverse osmosis plant being temporarily idled in April and May 2013.

Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of $12 million to cost of goods sold in the six months ended June 30, 2013 and a decrease of $10 million to cost of goods sold in the six months ended June 30, 2012. Produced low volatile metallurgical coal inventory was 0.1 million tons at June 30, 2013 compared to 0.3 million tons at June 30, 2012.

OTHER COAL SEGMENT

The other coal segment had a loss before income tax of $190 million for the six months ended June 30, 2013 and had zero net income before taxes for the six months ended June 30, 2012. 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.

Other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamation process at idled facilities for the six months ended June 30, 2012. No coal was recovered during the reclamation process at idled facilities for the six months ended June 30, 2013. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental to total Company production or sales.

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 $11 million for the six months ended June 30, 2013 compared to $8 million for the six months ended June 30, 2012.

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 $24 million for the six months ended June 30, 2013 compared to $99 million for the six months ended June 30, 2012. The $75 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

Miscellaneous other income was $61 million for the six months ended June 30, 2013 compared to $211 million for the six months ended June 30, 2012. The $150 million decrease is due to the following items:

•

Gain on sale of assets attributable to the Other Coal segment was $27 million in the six months ended June 30, 2013 compared to $180 million in the six months ended June 30, 2012. The decrease of $153 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in income of $22 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in income of $25 million. See Note 2—Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of these sales. The remaining change was related to various transactions that occurred throughout both periods, none of which were individually material.


•	Equity in earnings of affiliates increased $5 million due to higher earnings from our equity affiliates.


•	In the six months ended June 30, 2013, $3 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyor accident. There is no assurance that additional proceeds from the incident will be received.


•	In the six months ended June 30, 2012, there was an additional $6 million in income that was related to certain thermal coal contract buyouts. There were no such items in the six months ended June 30, 2013.


•	The remaining $1 million decrease in other income is due to various items, none of which are individually material.

Other coal segment total costs were $286 million for the six months ended June 30, 2013 compared to $324 million for the six months ended June 30, 2012. The decrease of $38 million was due to the following items:



	For the Six Months Ended June 30,
	2013		2012		Variance
Blacksville No. 2 Mine Fire	$	38	$	—	$	38
Stock-based compensation	25		16		9
Purchased coal	21		18		3
Closed and idle mines	68		71		(3		)
Freight expense	24		99		(75		)
Other	110		120		(10		)
Total Other Coal Segment Costs	$	286	$	324	$	(38	)


•	The Blacksville No. 2 Mine fire expense was due to a fire that occurred on March 12, 2013. The mine resumed production on May 20, 2013. Insurance recovery is uncertain at this time and the impact of any potential recovery has not been reflected in the six months ended June 30, 2013.

•


•	Purchased coal costs increased due to an increase in the amount of coal that was purchased to fulfill various contracts.

•

Closed and idle mine costs decreased approximately $3 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. There was a $24 million decrease in asset retirement obligations. This was primarily due to an increase in the reclamation liability at the Fola Mining Complex in the June 2012 period due to new regulatory requirements, and water and selenium treatment estimates. The decrease was offset, in part, by an increase of $13 million due to the idling of the Fola Mining Complex in August 2012, and an increase of $5 million due to the idling of the Amonate Complex in September 2012. The remaining increase of $3 million was due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.

•


•	Other expenses related to the coal segment decreased $10 million due to various transactions that occurred throughout both periods, none of which were individually material.

TOTAL GAS SEGMENT ANALYSIS for the six months ended June 30, 2013 compared to the six months ended June 30, 2012:

The gas segment had a loss of $5 million before income tax in the six months ended June 30, 2013 compared to earnings of $13 million in the six months ended June 30, 2012.



	For the Six Months Ended													Difference to Six Months Ended
	June 30, 2013													June 30, 2012
	CBM		Shallow Oil and Gas			Marcellus		Other Gas			Total Gas			CBM			Shallow Oil and Gas			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	172	$	66		$	95	$	6		$	339		$	(15	)	$	(3	)	$	47	$	2		$	31
Related Party	2		—			—		—			2			1			—			—		—			1
Total Outside Sales	174		66			95		6			341			(14		)	(3		)	47		2			32
Gas Royalty Interest	—		—			—		31			31			—			—			—		9			9
Purchased Gas			—			—		3			3			—			—			—		1			1
Other Income	—		—			—		24			24			—			—			—		(10		)	(10		)
Total Revenue and Other Income	174		66			95		64			399			(14		)	(3		)	47		2			32
Lifting	19		17			9		2			47			—			(4		)	3		1			—
Ad Valorem, Severance, and Other Taxes	4		6			3		(1		)	12			(1		)	1			1		(1		)	—
Gathering	58		19			19		1			97			7			8			10		—			25
Gas Direct Administrative, Selling & Other	4		4			13		2			23			(5		)	(4		)	8		(1		)	(2		)
Depreciation, Depletion and Amortization	45		30			26		4			105			2			—			8		(2		)	8
General & Administration	—		—			—		22			22			—			—			—		3			3
Gas Royalty Interest	—		—			—		25			25			—			—			—		8			8
Purchased Gas	—		—			—		2			2			—			—			—		1			1
Exploration and Other Costs	—		—			—		21			21			—			—			—		—			—
Other Corporate Expenses	—		—			—		46			46			—			—			—		6			6
Interest Expense	—		—			—		4			4			—			—			—		1			1
Total Cost	130		76			70		128			404			3			1			30		16			50
Earnings Before Income Tax	$	44	$	(10	)	$	25	$	(64	)	$	(5	)	$	(17	)	$	(4	)	$	17	$	(14	)	$	(18	)

COALBED METHANE (CBM) GAS SEGMENT

The CBM segment contributed $44 million to the total Company earnings before income tax for the six months ended June 30, 2013 compared to $61 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Produced Gas CBM sales volumes (in billion cubic feet)	41.6		45.1		(3.5		)	(7.8	)%
Average CBM sales price per thousand cubic feet sold	$	4.17	$	4.18	$	(0.01	)	(0.2	)%
Average CBM lifting costs per thousand cubic feet sold	0.46		0.43		0.03			7.0	%
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold	0.09		0.12		(0.03		)	(25.0	)%
Average CBM gathering costs per thousand cubic feet sold	1.39		1.12		0.27			24.1	%
Average CBM direct administrative, selling & other costs per thousand cubic feet sold	0.09		0.21		(0.12		)	(57.1	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	1.09		0.95		0.14			14.7	%
Total Average CBM costs per thousand cubic feet sold	3.12		2.83		0.29			10.2	%
Average Margin for CBM	$	1.05	$	1.35	$	(0.30	)	(22.2	)%

CBM sales revenues were $174 million in the six months ended June 30, 2013 compared to $188 million for the six months ended June 30, 2012. The $14 million decrease was primarily due to an 7.8% decrease in volumes sold and a 0.2% decrease in average sales price per thousand cubic feet sold. CBM sales volumes decreased 3.5 billion cubic feet for the six months ended June 30, 2013 compared to the 2012 period primarily due to normal well declines without a corresponding increase in wells drilled. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage. The decrease in CBM average sales price was the result of higher average market prices offset by various gas swap transactions that matured in each period. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 20.6 billion cubic feet of our produced CBM gas sales volumes for the six months ended June 30, 2013 at an average price of $4.60 per thousand cubic feet. For the six months ended June 30, 2012, these financial hedges represented 23.1 billion cubic feet at an average price of $5.33 per thousand cubic feet.

Total costs for the CBM segment were $130 million for the six months ended June 30, 2013 compared to $127 million for the six months ended June 30, 2012. The increase in total costs for the CBM segment are due to the following items:

•CBM lifting costs were $19 million for the six months ended June 30, 2013 and 2012. The $0.03 per thousand cubic feet increase in average lifting costs during the current year is directly related to the decrease in gas sales volumes.

•CBM ad valorem, severance and other taxes were $4 million for the six months ended June 30, 2013 compared to $5 million for the six months ended June 30, 2012. The $1 million decrease in total dollars was primarily due to a reassessment of our 2012 ad valorem taxes paid to Tazewell County, Virginia resulting in a current period refund. Decreased ad valorem and severance expense resulted in a decrease in average unit costs, offset, in part, by an increase due to the reduction of volumes.

•CBM gathering costs were $58 million for the six months ended June 30, 2013 compared to $51 million for the six months ended June 30, 2012. This $7 million increase in total dollars and the $0.27 per thousand cubic feet increase in average CBM gathering unit costs are related to increased power costs due to higher utility rates, increased pipeline maintenance expense, increased road maintenance expenses and lower volumes sold in the period-to-period comparison.

•CBM direct administrative, selling and other costs for the CBM segment were $4 million for the six months ended June 30, 2013 compared to $9 million for the six months ended June 30, 2012. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The decrease in direct administrative, selling & other costs was primarily due to reduced direct administrative labor and CBM volumes representing a smaller proportion of total natural gas volumes sold. Improvements in unit costs were offset, in part, by the reduction in volumes.

•Depreciation, depletion and amortization attributable to the CBM segment was $45 million for the six months ended June 30, 2013 compared to $43 million for the six months ended June 30, 2012. There was approximately $31 million, or $0.75

per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the six months ended June 30, 2013. The production portion of depreciation, depletion and amortization was $30 million, or $0.66 per unit-of-production in the six months ended June 30, 2012. There was approximately $14 million, or $0.34 average per unit cost of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the six months ended June 30, 2013. The non-production related depreciation, depletion and amortization was $13 million, or $0.29 per thousand cubic feet for the six months ended June 30, 2012.

SHALLOW OIL AND GAS SEGMENT

The Shallow Oil and Gas segment had a loss before income tax of $10 million for the six months ended June 30, 2013 compared to a loss before income tax of $6 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013			2012			Variance			Percent Change
Produced Gas Shallow Oil and Gas sales volumes (in billion cubic feet)	13.8			14.8			(1.0		)	(6.8	)%
Average Shallow Oil and Gas sales price per thousand cubic feet sold	$	4.78		$	4.63		$	0.15		3.2	%
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold	1.22			1.39			(0.17		)	(12.2	)%
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold	0.40			0.32			0.08			25.0	%
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold	1.39			0.78			0.61			78.2	%
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold	0.33			0.56			(0.23		)	(41.1	)%
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold	2.14			1.99			0.15			7.5	%
Total Average Shallow Oil and Gas costs per thousand cubic feet sold	5.48			5.04			0.44			8.7	%
Average Margin for Shallow Oil and Gas	$	(0.70	)	$	(0.41	)	$	(0.29	)	70.7	%

Shallow Oil and Gas sales revenues were $66 million for the six months ended June 30, 2013 compared to $69 million for the six months ended June 30, 2012. The $3 million decrease was primarily due to the 6.8% decrease in volumes sold, offset, in part, by a 3.2% increase in average sales price. The increase in shallow oil and gas average sales price is the result of higher average market prices offset by various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 6.8 billion cubic feet of our produced shallow oil and gas sales volumes for the six months ended June 30, 2013 at an average price of $5.24 per thousand cubic feet. For the six months ended June 30, 2012, these financial hedges represented 9.5 billion cubic feet at an average price of $5.23 per thousand cubic feet.

Total costs for the shallow oil and gas segment were $76 million for the six months ended June 30, 2013 compared to $75 million for the six months ended June 30, 2012. The increase in total costs for the shallow oil and gas segment are due to the following items:

•Shallow Oil and Gas lifting costs were $17 million for the six months ended June 30, 2013 compared to $21 million for the six months ended June 30, 2012. The $4 million decrease to total costs and $0.17 per thousand cubic feet decrease in average unit costs is due to lower road maintenance, lower salt water disposal costs and lower contract services in the current period, offset, in part, by an increase in accretion expense on the well plugging liability.

•Shallow Oil and Gas ad valorem, severance and other taxes were $6 million for the six months ended June 30, 2013 and $5 million for the six months ended June 30, 2012. The $1 million increase to total costs is primarily due to higher average sales prices in the current period. The $0.08 per thousand cubic feet increase to average unit costs is due to higher average sales prices and lower sales volumes.

•Shallow Oil and Gas gathering costs were $19 million for the six months ended June 30, 2013 compared to $11 million for the six months ended June 30, 2012. Gathering costs increased $8 million primarily due to increased firm transportation costs in the period-to-period comparison.

•Shallow Oil and Gas direct administrative, selling and other costs were $4 million for the six months ended June 30, 2013 compared to $8 million for the six months ended June 30, 2012. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The $4 million decrease in the period-to-period comparison is due to reduced direct administrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes sold. The decrease in costs were offset, in part, by lower sales volumes.

•Depreciation, depletion and amortization costs remained consistent at $30 million for the six months ended June 30, 2013 and 2012. There was approximately $26 million, or $1.87 per unit-of production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2013. There was approximately $26 million, or $1.74 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2012. There was approximately $4 million, or $0.27 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the six months ended June 30, 2013. There was $4 million, or $0.25 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the six months ended June 30, 2012.

MARCELLUS GAS SEGMENT

The Marcellus segment contributed $25 million to the total Company earnings before income tax for the six months ended June 30, 2013 compared to $8 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Produced Gas Marcellus sales volumes (in billion cubic feet)	21.0		13.9		7.1			51.1	%
Average Marcellus sales price per thousand cubic feet sold	$	4.51	$	3.41	$	1.10		32.3	%
Average Marcellus lifting costs per thousand cubic feet sold	0.45		0.43		0.02			4.7	%
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold	0.14		0.14		—			—	%
Average Marcellus gathering costs per thousand cubic feet sold	0.89		0.61		0.28			45.9	%
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold	0.60		0.34		0.26			76.5	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	1.22		1.31		(0.09		)	(6.9	)%
Total Average Marcellus costs per thousand cubic feet sold	3.30		2.83		0.47			16.6	%
Average Margin for Marcellus	$	1.21	$	0.58	$	0.63		108.6	%

The Marcellus segment sales revenues were $95 million for the six months ended June 30, 2013 compared to $48 million for the six months ended June 30, 2012. The $47 million increase is primarily due to a 51.1% increase in volumes sold, and a 32.3% increase in 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 on-going drilling program. The increase in Marcellus average sales price was the result of the improvement in general market prices and sales of natural gas liquids, offset by various gas swap transactions that matured in the six months ended June 30, 2013. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 8.8 billion cubic feet of our produced Marcellus gas sales volumes for the six months ended June 30, 2013 at an average price of $4.74 per thousand cubic feet. For the six months ended June 30, 2012, these financial hedges represented 5.5 billion cubic feet at an average price of $4.97 per thousand cubic feet.

Total costs for the Marcellus segment were $70 million for the six months ended June 30, 2013 compared to $40 million for the six months ended June 30, 2012. The increase in total costs for the Marcellus segment are due to the following items:

•Marcellus lifting costs were $9 million for the six months ended June 30, 2013 compared to $6 million for the six months ended June 30, 2012. The increase primarily relates to an increase in salt water disposal costs, road maintenance costs, and well tending costs.

•Marcellus ad valorem, severance and other taxes were $3 million for the six months ended June 30, 2013 compared to $2 million for the six months ended June 30, 2012. The increase relates to the higher average sales price and an increase in volumes sold, as the per-unit costs remained consistent for the 2013 and 2012 periods.

•Marcellus gathering costs were $19 million for the six months ended June 30, 2013 compared to $9 million for the six months ended June 30, 2012. Average gathering costs increased $0.28 per unit primarily due to increased firm transportation costs, and increased processing fees associated with natural gas liquids.

•Marcellus direct administrative, selling and other costs were $13 million for the six months ended June 30, 2013 compared to $5 million for the six months ended June 30, 2012. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gas segments based on a combination of production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellus volumes representing a larger proportion of total natural gas volumes. The impact on average unit costs from the increase in direct administrative labor was offset by higher volumes sold.

•Depreciation, depletion and amortization costs were $26 million for the six months ended June 30, 2013 compared to $18 million for the six months ended June 30, 2012. There was approximately $25 million, or $1.20 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the six months ended June 30, 2013. There was approximately $16 million, or $1.17 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation for the six months ended June 30, 2012. There was approximately $1 million, or $0.02 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the six months ended June 30, 2013. There was $2 million, or $0.14 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment reflected on a straight line basis for the six months ended June 30, 2012.

OTHER GAS SEGMENT

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee and the Utica Shale in Ohio. Revenue from these operations were approximately $6 million for the six months ended June 30, 2013 and $4 million for the six months ended June 31, 2012. Total costs related to these other sales were $8 million for the six months ended June 30, 2013 and $11 million for the six months ended June 30, 2012. A per unit analysis of the other operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the 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 gas segment. Royalty interest gas sales revenue was $31 million for the six months ended June 30, 2013 compared to $22 million for the six months ended June 30, 2012. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period increase.



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	7.4		8.3		(0.9		)	(10.8	)%
Average Sales Price Per thousand cubic feet	$	4.21	$	2.61	$	1.60		61.3	%

Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $3 million for the six months ended June 30, 2013 and $2 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013		2012		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)	0.7		0.6		0.1		16.7	%
Average Sales Price Per thousand cubic feet	$	3.69	$	2.70	$	0.99	36.7	%

Other income was $24 million for the six months ended June 30, 2013 compared to $34 million for the six months ended June 30, 2012. The $10 million change was primarily due to a $7 million decrease in interest income related to the timing of collections on the notes receivable from the Noble joint venture transaction, a $2 million decrease in gains on dispositions of non-core acreage and equipment, and a $1 million decrease in various other transactions, none of which are individually material.

General and administrative costs are allocated to the total gas segment based on percentage of total revenue and percentage of total projected capital expenditures. Costs were $22 million for the six months ended June 30, 2013 and $19 million for the six months ended June 30, 2012. 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 gas segment. Royalty interest gas costs were $25 million for the six months ended June 30, 2013 compared to $17 million for the six months ended June 30, 2012. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change.



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)	7.4		8.3		(0.9		)	(10.8	)%
Average Cost Per thousand cubic feet sold	$	3.42	$	2.08	$	1.34		64.4	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. 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 $2 million for the six months ended June 30, 2013 and $1 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013		2012		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)	0.7		0.6		0.1		16.7	%
Average Cost Per thousand cubic feet sold	$	2.70	$	1.94	$	0.76	39.2	%

Exploration and other costs remained consistent at $21 million for the six months ended June 30, 2013 and 2012.



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Marcellus Title Defects	$	9	$	—	$	9		100	%
Exploration	9		9		—			—	%
Lease Expiration Costs	3		12		(9		)	(75	)%
Total Exploration and Other Costs	$	21	$	21	$	—		—	%


•	As part of the title defect process the company is working through with its joint venture partner, Noble Energy, CONSOL Energy conceded title defects on acreage which had a book value to CONSOL Energy of $9 million.


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


•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $9 million decrease is due to CONSOL Energy allowing less leases to expire in the current period when compared with the prior period.

Other corporate expenses were $46 million for the six months ended June 30, 2013 compared to $40 million for the six months ended June 30, 2012. The $6 million increase in the period-to-period comparison was made up of the following items:



	For the Six Months Ended June 30,
	2013		2012		Variance			Percent Change
Unutilized firm transportation	$	16	$	5	$	11		220	%
Stock-based compensation	14		10		4			40	%
Legal fees	2		2		—			—	%
Bank fees	3		4		(1		)	(25	)%
PA Impact fees	—		4		(4		)	(100	)%
Short-term incentive compensation	9		14		(5		)	(35.7	)%
Other	2		1		1			100	%
Total Other Corporate Expenses	$	46	$	40	$	6		15	%


•	Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase. The $11 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

•

Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense and accelerated non-cash amortization for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to the prior year's quarter. The new program replaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.


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


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

•

PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. On-going PA impact fees which relate to current year wells drilled are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.


•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense was lower for the 2013 period compared to the 2012 period due to the projected lower payouts.


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

Interest expense related to the gas segment was $4 million for the six months ended June 30, 2013 compared to $3 million for the six months ended June 30, 2012. Interest was incurred by the gas segment on the CNX Gas revolving credit facility and a capital lease. The $1 million increase was primarily due to higher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the six months ended June 30, 2013 compared to the six months ended June 30, 2012:

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 $153 million for the six months ended June 30, 2013 compared to a loss before income tax of $102 million for the six months ended June 30, 2012. The other segment also includes total Company income tax expense of $15 million for the six months ended June 30, 2013 compared to $80 million for the six months ended June 30, 2012.



	For the Six Months Ended June 30,
	2013			2012			Variance			Percent Change
Sales—Outside	$	169		$	193		$	(24	)	(12.4	)%
Other Income	8			7			1			14.3	%
Total Revenue	177			200			(23		)	(11.5	)%
Cost of Goods Sold and Other Charges	207			172			35			20.3	%
Depreciation, Depletion & Amortization	13			12			1			8.3	%
Taxes Other Than Income Tax	6			6			—			—	%
Interest Expense	104			112			(8		)	(7.1	)%
Total Costs	330			302			28			9.3	%
Loss Before Income Tax	(153		)	(102		)	(51		)	50.0	%
Income Tax	15			80			(65		)	(81.3	)%
Net Loss	$	(168	)	$	(182	)	$	14		(7.7	)%

Industrial supplies:

Outside sales from industrial supplies was $108 million for the six months ended June 30, 2013 compared to $134 million for the six months ended June 30, 2012. The decrease of $26 million was primarily related to lower sales volumes.

Total costs related to industrial supply sales were $106 million for the six months ended June 30, 2013 compared to $130 million for the six months ended June 30, 2012. The decrease of $24 million was primarily related to lower sales volumes and various changes in inventory costs, none of which were individually material.

Transportation operations:

Outside sales from transportation operations was $61 million for the six months ended June 30, 2013 compared to $59 million for the six months ended June 30, 2012. The increase of $2 million was primarily attributable to higher per ton thru-put rates at the CNX Marine Terminal offset, in part, by decreased thru-put.

Total costs related to the transportation operations were $50 million for the six months ended June 30, 2013 compared to $42 million for the six months ended June 30, 2012. The increase of $8 million was due to various items in both periods, none of which were individually material.

Miscellaneous other:

Additional other income of $8 million was recognized for the six months ended June 30, 2013 compared to $7 million for the six months ended June 30, 2012. The $1 million increase was primarily due to an increase in interest income.

Other corporate costs in the other segment were $174 million for the six months ended June 30, 2013 compared to $130 million for the six months ended June 30, 2012. Other corporate costs increased due to the following items:



	For the Six Months Ended June 30,
	2013		2012		Variance
Pension Settlement	$	32	$	—	$	32
CNX Gas shareholder settlement	20		—		20
Bank fees	7		7		—
Interest Expense	104		113		(9		)
Other	11		10		1
	$	174	$	130	$	44


•	Pension settlement adjustment is the result of accounting rules requiring acceleration of unrecognized actuarial losses when lump sum payments from a plan exceed the annual projected service and interest costs of the plan.


•	The CNX Gas shareholder settlement is 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 the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total

settlement provides for a payment to the plaintiffs of $42.73 million, of which the Company expects to pay $20.2 million. This settlement is subject to court approval and to the execution of final agreements with the parties.


•	Bank Fees remained consistent throughout both periods.


•	Interest expense decreased $9 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.


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

Income Taxes:

The effective income tax rate was 2,969.4% for the six months ended June 30, 2013 compared to 24.3% for the six months ended June 30, 2012. The effective rates for the six months ended June 30, 2013 and 2012 were calculated using the annual effective rate projection on recurring earnings and include tax liabilities related to certain discrete transactions. The relationship between pre-tax earnings and percentage depletion impacts the effective tax rate. See Note 5—Income Taxes of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.



	For the Six Months Ended June 30,
	2013			2012			Variance			Percent Change
Total Company Earnings Before Income Tax	$	1		$	330		$	(329	)	(99.6	)%
Income Tax Expense	$	15		$	80		$	(65	)	(80.9	)%
Effective Income Tax Rate	2,969.4		%	24.3		%	2,945.1		%

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 $1.5 billion Senior Secured Credit Agreement expires April 12, 2016. 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 $1.5 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 earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio is calculated as the ratio of EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 3.44 to 1.00 at June 30, 2013. The facility includes a maximum leverage ratio covenant of no more than 4.50 to 1.00, measured quarterly. The leverage ratio is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CONSOL Energy and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, for CONSOL Energy and certain of its subsidiaries. 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 plus pro-rata earnings from material acquisitions. The leverage ratio was 3.65 to 1.00 at June 30, 2013. 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 EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on the revolving credit facility. The senior secured leverage ratio was 0.12 to 1.00 at June 30, 2013. 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 June 30, 2013, the facility had no outstanding borrowings and $100 million of letters of credit outstanding, leaving $1.4 billion of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, up to $200 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is based on commercial paper rates plus a charge for administrative services paid to financial institutions. At June 30, 2013, eligible accounts receivable totaled approximately $181 million. At June 30, 2013, the facility had $41 million of outstanding borrowings and $159 million of letters of credit outstanding.

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 EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratio was 36.85 to 1.00 at June 30, 2013. 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 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. 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 1.20 to 1.00 at June 30, 2013. 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 June 30, 2013, the facility had $173 million drawn and $70 million of letters of credit outstanding, leaving $757 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 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 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 $116 million at June 30, 2013. The ineffective portion of these contracts was a loss of $3.8 million and $2.7 million during the three and six months ended June 30, 2013. 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 in the future on terms which CONSOL Energy finds acceptable, or at all.

Cash Flows (in millions)



	For the Six Months Ended June 30,
	2013			2012			Change
Cash flows from operating activities	$	393		$	368		$	25
Cash used in investing activities	$	(465	)	$	(484	)	$	19
Cash used in financing activities	$	122		$	(59	)	$	181

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


•	Operating cash flow decreased $265 million in 2013 due to lower net income in the period-to-period comparison.


•	Operating cash flows increased $157 million in the period-to-period comparison due to changes in the gains on the sale of assets. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional details.


•	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 increased $44 million in the period-to-period comparison due to:

◦

Coal segment capital expenditures decreased $94 million. The decrease was comprised of $54 million related to the completion of the Northern West Virginia RO system as well as a $55 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material. Mineral lease expenditures associated with our advance mining royalties and leased coal assets also decreased $5 million in 2013. The decrease is offset, in part, by an increase of $20 million in longwall shield projects;


◦	Gas segment capital expenditures increased $154 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions in Monroe and Noble Counties in Ohio, and various other individually insignificant projects;


◦	Other capital expenditures decreased $16 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	Proceeds from the sale of assets decreased $11 million in the period-to-period comparison due to:


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


◦	$68 million received in May 2013 related to the Robinson Run longwall shield sale-leaseback;


◦	$64 million received in March 2013 related to the Shoemaker Mine longwall shield sale-leaseback;


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


◦	$170 million received in June 2012 related to the sale of Youngs Creek;


◦	$26 million received in April 2012 related to sale of Elk Creek; and


◦	$43 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.


•	Distributions from/investments in equity affiliates increased $5 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.


•	The release of $69 million of restricted cash of which $48 million is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012. The remaining $21 million is associated with the Ryerson Dam Settlement.

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


•	In 2013, CONSOL Energy received $173 million of short term borrowings under the revolving credit facilities.


•	In 2013, CONSOL Energy repaid $30 million of borrowings related to a miscellaneous short term note payable and only $5 million in the 2012 period.


•	The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in the first quarter of 2013 and $29 million in dividends paid in the second quarter of 2013. As compared to $57 million in dividends paid in the six months ended June 30, 2012.


•	In 2013, CONSOL Energy received $3 million of borrowing under its Securitization Facility.


•	$2 million in additional cash received due to various other transactions that occurred throughout both periods, none of which were individually material.

The following is a summary of our significant contractual obligations at June 30, 2013 (in thousands):



	Payments due by Year
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	173,000	$	—	$	—	$	—	$	173,000
Borrowings Under Securitization Facility	40,719		—		—		—		40,719
Purchase Order Firm Commitments	174,317		6,297		—		—		180,614
Gas Firm Transportation	84,063		157,943		131,751		405,934		779,691
Long-Term Debt	4,585		8,488		1,505,220		1,610,292		3,128,585
Interest on Long-Term Debt	245,428		491,294		371,007		307,353		1,415,082
Capital (Finance) Lease Obligations	8,837		13,967		11,777		22,006		56,587
Interest on Capital (Finance) Lease Obligations	3,702		5,731		4,101		2,831		16,365
Operating Lease Obligations	131,738		242,520		171,199		155,385		700,842
Long-Term Liabilities—Employee Related (a)	223,458		441,956		435,786		2,307,981		3,409,181
Other Long-Term Liabilities (b)	242,092		184,738		82,254		482,786		991,870
Total Contractual Obligations (c)	$	1,331,939	$	1,552,934	$	2,713,095	$	5,294,568	$	10,892,536

_________________________


(a)	Long-Term Liabilities - Employee Related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2013 contributions are expected to approximate $50 million.


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


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

Debt

At June 30, 2013, CONSOL Energy had total long-term debt and capital lease obligations of $3.185 billion outstanding, including the current portion of long-term debt of $13 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 $20 million with an average interest rate of 7.43% per annum.


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


•	An aggregate principal amount of $57 million of capital leases with a weighted average interest rate of 6.35% per annum.

At June 30, 2013, CONSOL Energy also had no outstanding borrowings and had approximately $100 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At June 30, 2013, CONSOL Energy had $41 million in outstanding borrowings and had $159 million of letters of credit outstanding under the accounts receivable securitization facility.

At June 30, 2013, CNX Gas, a wholly owned subsidiary of CONSOL Energy, had $173 million in outstanding borrowings and approximately $70 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 $4.0 billion at June 30, 2013 and at December 31, 2012. Total equity remained consistent in the period-to-period analysis primarily due to a decrease in actuarial liabilities associated with the March 31, 2013 and June 30, 2013 pension plan remeasurements, an increase related to stock-based compensation, offset by changes in the fair value of cash flow hedges and treasury stock activity. See the Consolidated Statements of Stockholders' Equity in Item 1 of this Form 10-Q for additional details.

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



Declaration Date	Amount Per Share		Record Date	Payment Date
July 26, 2013	$	0.125	August 9, 2013	August 23, 2013
April 26, 2013	$	0.125	May 10, 2013	May 24, 2013

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 3.65 to 1.00 and our availability was approximately $1.4 billion at June 30, 2013. 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 six months ended June 30, 2013.

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. CONSOL Energy participates in various multi-employer benefit plans such as the UMWA 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at June 30, 2013. The various multi-employer benefit plans are discussed in Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of the December 31, 2012 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 balance sheet at June 30, 2013. 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.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following: a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and b.) Any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting from joint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of this new guidance will not have a material impact on CONSOL Energy's financial statements.

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 Exchange Act) 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 coal and natural gas 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 coal and natural gas to market;


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


•	our inability to maintain satisfactory labor relations;


•	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 coal and natural gas;


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


•	the risks inherent in coal and natural gas 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 coal and gas 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 coal and natural gas operations;


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


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


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


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


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


•	defects may exist in our chain of title and we may incur additional costs associated with perfecting title for coal or gas 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;


•	exposure to multi-employer pension plan liabilities;


•	minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;


•	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;


•	the anti-takeover effects of our rights plan could prevent a change of control;


•	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; and


•	other factors discussed in our 2012 Form 10-K under “Risk Factors,” which is 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, collar-price contracts 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 2012 Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at June 30, 2013. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $45.2 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $45.1 million.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At June 30, 2013, CONSOL Energy had $3,185 million aggregate principal amount of debt outstanding under fixed-rate instruments and $214 million aggregate principal 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 at June 30, 2013. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly increased the net loss for the period. CNX Gas’ facility had outstanding borrowings of $173 million at June 30, 2013 and bore interest at a weighted average rate of 1.76% per annum during the six months ended June 30, 2013. Due to the level of borrowings against this facility and the low weighted average interest rate in the six months ended June 30, 2013, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly increased the net loss for the period.

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

Hedging Volumes

As of July 9, 2013 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
2013 Fixed Price Volumes
Hedged Mcf	N/A		N/A		24,046,537		24,046,537		48,093,074
Weighted Average Hedge Price per thousand cubic feet	N/A		N/A		$	4.62	$	4.62	$	4.62
2014 Fixed Price Volumes
Hedged Mcf	16,634,945		16,819,778		17,004,611		17,004,611		67,463,945
Weighted Average Hedge Price per thousand cubic feet	$	4.92	$	4.92	$	4.92	$	4.92	$	4.92
2015 Fixed Price Volumes
Hedged Mcf	13,194,340		13,340,943		13,487,547		13,487,547		53,510,377
Weighted Average Hedge Price per thousand cubic feet	$	4.24	$	4.24	$	4.24	$	4.24	$	4.24
2016 Fixed Price Volumes
Hedged Mcf	7,125,472		7,125,472		7,203,774		7,203,774		28,658,492
Weighted Average Hedge Price per thousand cubic feet	$	4.45	$	4.45	$	4.45	$	4.45	$	4.45


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2013 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 nineteenth 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 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			Stipulation and Agreement of Compromise and Settlement, dated May 8, 2013, between and among (i) plaintiffs Harold L. Hurwitz and James R. Gummel, on their own behalf and on behalf of the Class (as defined therein) and (ii) defendants CNX Gas Corporation, CONSOL Energy Inc. and certain individual defendants.

10.2			Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble Energy, Inc.

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

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

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

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

95			Mine Safety and Health Administration Safety Data.

101			Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2013 furnished in XBRL).

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

SIGNATURES

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

Dated: August 5, 2013



	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)