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ITEM 1.	CONDENSED FINANCIAL STATEMENTS

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(A)	Includes equity in earnings of unconsolidated affiliates of $4,842, $693 and $3,142 for Coal, Gas and All Other, respectively.

(B)	Includes investments in unconsolidated equity affiliates of $33,037, $91,853 and $50,928 for Coal, Gas and All Other, respectively.

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(C)	Includes equity in earnings of unconsolidated affiliates of $4,142, $785 and $1,976 for Coal, Gas and All Other, respectively.

(D)	Includes investments in unconsolidated equity affiliates of $20,472, $24,651 and $47,138 for Coal, Gas and All Other, respectively.

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(F)	Includes investments in unconsolidated equity affiliates of $33,037, $91,853 and $50,928 for Coal, Gas and All Other, respectively.

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(H)	Includes investments in unconsolidated equity affiliates of $20,472, $24,651 and $47,138 for Coal, Gas and All Other, respectively.

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

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•	On October 27, 2011, CONSOL Energy's Board of Directors increased the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share.

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On October 21, 2011, CONSOL Energy, through its subsidiary, CNX Gas Company LLC, completed a sale to Hess Ohio Developments, LLC (Hess) of 50% of its nearly 200,000 Utica Shale acres in Ohio for consideration of approximately $594 million, of which $60 million was paid at closing. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534 million in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. CONSOL Energy and Hess anticipate commencing initial drilling operations in the fourth quarter of 2011.

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On September 30, 2011, CNX Gas Company LLC (CNX Gas) 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 628,000 acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. On September 30, 2011, cash proceeds of $519 million were received from Noble. In addition to the cash proceeds, a one year note receivable due on September 30, 2012 in the amount of $312 million and a two year note receivable due on September 30, 2013 in the amount of $296 million have been recorded. As part of the transaction, CONSOL Energy 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 $2.1 billion with certain restrictions.

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On September 30 2011, CNX Gas and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CONSOL Energy contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $133 million and Noble contributed cash of approximately $73 million. On September 30, 2011, CONE made a cash distribution to CONSOL Energy in the amount of $73 million.

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On September 21, 2011, CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in 115,647 net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193 million. The transaction became effective as of July 1, 2011.

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CONSOL Energy incurred costs of approximately $15 million in the three months ended September 30, 2011 related to the solicitation of consents from the holders of CONSOL's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment of the indentures for each of those notes, clarifying that the transactions contemplated by the August 2011 Asset Acquisition Agreements with Noble Energy and Hess Energy were permissible under those indentures.

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In June 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collective bargaining agreement which will run from July 1, 2011 to December 31, 2016. That agreement, National Bituminous Coal Wage Agreement of 2011 (2011 NBCWA) covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA that was set to expire on December 31, 2011. Key elements of the new agreement include the following items:

a.	A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1st throughout the contract term.

b.

Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. New inexperienced miners hired after December 31, 2011 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of experience will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the CDSP beginning January 1, 2012. All current UMWA represented employees will be given the opportunity to opt-out of future participation in the 1974 Pension Plan and instead participate in the CDSP.

c.	A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.

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d.	An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.

e.	Various other changes related to absenteeism, contribution to various UMWA benefit funds, eligibility for various vacation days and sick days.

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On October 24, 2011, certain subsidiaries of CONSOL Energy received notice from the trustees of the UMWA 1974 Pension Plan ("the Plan") stating that the Plan is considered to be in “seriously endangered” status for the plan year beginning July 1, 2011.  The status of the plan is due to the funded percentage and projected funding deficiency.  As a result, the Pension Protection Act requires the Plan to adopt a funding improvement plan no later than May 25, 2012, to improve the funded status of the Plan, which may include increased contributions to the Plan from employers in the future.  Because CONSOL Energy's subsidiaries are parties to the NBCWA which establishes their contribution obligations through December 31, 2016, such subsidiaries' contributions to the Plan will not increase as a consequence of any funding improvement plan adopted by the Plan to address the Plan's seriously endangered status.

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In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle status since March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided it was in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The Company redeployed all of the movable equipment from the mine that could be used at other locations. The abandonment of this underground facility resulted in a $115 million charge to pre-tax earnings in June 2011. See Note 8—Property, Plant and Equipment in the Notes to the Consolidated Financial Statements of this Form 10-Q for additional disclosure. The Company expects the closure of Mine 84 to result in pre-tax cash savings of $18 million per year.

•	In April 2011, CNX Gas entered into an amendment of its senior secured credit agreement which increases the availability under the agreement from $700 million to $1.0 billion, decreases the interest rate and extends the term from May 6, 2014 to April 12, 2016. The amended credit agreement continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries.

•	In April 2011, CONSOL Energy amended and extended its existing $1.5 billion senior secured credit agreement, which decreases the interest rate and extends the term from May 7, 2014 to April 12, 2016. The amended agreement continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries.

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On March 9, 2011, CONSOL Energy issued $250 million of 6.375% senior notes due March 2021. The Notes are guaranteed by substantially all of the Company's existing and future wholly owned domestic restricted subsidiaries. The Company issued the Notes with the intention of using the net proceeds to repay its outstanding 7.875% senior secured notes due March 1, 2012, on or before their maturity. On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing the notes. By using the proceeds of the $250 million, 6.375% senior notes due March 2021 to affect this redemption, the Company effectively extended the maturity of the $250 million of long-term indebtedness nine years at a lower interest rate. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million, for a total redemption cost of approximately $268 million. The loss on extinguishment of debt was approximately $16 million, which primarily represents the interest that would have been paid on these notes if they had been held to maturity.

•	Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel and synthetic rubber that we use in our operations and (ii) continued scrutiny of existing safety regulations and the development of new safety regulations.

•	Federal and state environmental regulators are reviewing our operations more closely and more strictly interpreting

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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. Further, other regulations would make it more expensive for our customers to operate their businesses, possibly inducing them to move to alternative fuel sources. For example, the EPA has issued a proposed rule that would regulate coal combustion residuals from coal fired electric generating facilities under the federal Resource Conservation and Recovery Act (RCRA) as either a hazardous waste under Subtitle C of RCRA or as a non-hazardous waste under Subtitle D of RCRA. If final rules are adopted consistent with either of the proposed alternatives, the cost of handling and disposal of coal combustion residuals could increase making it more expensive to generate electricity from coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011. CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed.

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On April 19, 2011, the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from Marcellus Shale operators. They called on operators to cease delivering wastewater to the POTWs by May 19, 2011. CONSOL Energy has implemented a re-cycle and re-use process of its Marcellus derived water for fracing operations, and will only safely dispose of Marcellus wastewater in regulated, underground injection control wells.

•	CONSOL Energy continues to explore potential sales of non-core assets.

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•	Employee wages and related expenses increased $2 million which was primarily attributable to additional hiring of support staff in the period-to-period comparison.

•	Advertising and promotion expense increased $2 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.

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

•	Consulting and professional services increased $1 million due to various corporate projects that occurred throughout both periods, none of which were individually material.

•	Miscellaneous selling, general and administrative expenses increased $1 million primarily due to various corporate projects that occurred throughout both periods, none of which were individually material.

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•	Average operating costs per steam ton sold increased due to fewer tons sold. Fixed costs are allocated over less tons, resulting in higher unit costs.

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Labor and related benefits average costs per ton sold were impaired, although total dollars expensed for these items were improved slightly. Average costs per ton sold were impacted by the 1.5 million ton reduction in sales tons. Labor benefit costs were impacted by the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event that the federal contributions are not sufficient to cover the benefits. This improvement was offset by higher contributions made to the 1974 Pension Trust (the Trust), which is a multi-employer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate has increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Reductions were also offset, in part, by additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison.

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Average operating supplies & maintenance cost per ton sold increased due to higher fuel costs, additional roof control costs, additional maintenance and equipment overhaul costs. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period.

•	Production taxes average cost per ton sold increased due to the $6.16 per ton higher average sales price.

•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs have also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

•	These increases in average operating costs per ton for steam coal were offset, in part, by lower contract mining fees. Fewer contractors were retained to mine our reserves in the period-to-period comparison without a corresponding reduction in total steam coal sold which has resulted in lower average unit costs per ton sold.

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Average operating costs per unit primarily changed due to the mix of mines shipping high volatile metallurgical coal. The increased cost structure of high volatile metallurgical coal is due to more Central Appalachian mines shipping high vol tons. Central Appalachian mines shipping high volatile metallurgical tons have higher cost structures than the Northern Appalachian mines included in the prior period.

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Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Higher non-union benefit rates for active employees were related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Labor and related benefits also increased due to the impact of the wage increase of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. Increased labor and related benefit costs per unit sold were offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.

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Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased

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•	Production taxes average cost per ton sold increased due to the $16.83 per ton higher average sales price.

•	In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the Central Appalachian mines now shipping high volatile metallurgical coal.

•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

•	Average preparation plant costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.

•	Average royalty costs per ton sold were lower in the period-to-period comparison due to fewer tons being mined from coal tracts that have a royalty, offset, in part, by higher average sales prices.

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•	Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.

•	Average preparation plant costs per ton sold increased due to additional maintenance projects completed and increased fuel costs at our preparation plant in the period-to-period comparison.

•	Labor and related benefits increased in the period-to-period comparison due to additional employees, increased hours worked and increased non-union benefit rates for active employees which were related to the continued increase in healthcare costs.

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Closed and idle mine costs decreased approximately $48 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. The decrease was the result of a $29 million increase in the Fola reclamation liability in the 2010 period as a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans. Also, closed and idle mine costs decreased $14 million as the result of the change in mine plan at Mine 84 in the 2010 period. Due to the mine plan change, a portion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $5 million 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.

•	Litigation expense decreased $1 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010 related to various legal settlements, none of which were individually material.

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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used for 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 in freight revenue. Freight expense increased $22 million primarily due to the 0.6 million ton increase in export tons in the period-to-period comparison.

•	Purchased coal costs increased approximately $9 million in the period-to-period comparison primarily due to the increased volumes of coal purchased to supply various coal sales contracts.

•	Other expenses related to the coal segment increased $1 million in the period-to-period comparison due to various miscellaneous transactions, none of which were individually material.

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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 increased in the period-to-period comparison as the result of exceeding the targets in the 2011 period and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.

•	Unutilized firm transportation represents excess pipeline transportation capacity that the gas division obtained to enable gas production to flow on an uninterrupted basis as the gas operations continue to increase sales volumes.

•	Contract buyout represents the cancellation of a drilling arrangement with a third-party well driller.

•	Stock-based compensation expense remained consistent in the period-to-period comparison.

•	Other corporate related expense decreased $4 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Transaction and financing fees of $15 million incurred in the three months ended September 30, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to CONSOL Energy's oil and gas properties.

•	Interest expense decreased $7 million in the period-to-period comparison primarily due to uncertain tax position adjustments related to the closure of federal income tax audits and lower borrowings on the revolving credit facility.

•	Bank fees decreased $1 million due to less borrowings on the revolving credit facility in the period-to-period comparison.

•	Evaluation fees for non-core asset dispositions remained consistent in the period-to-period comparison.

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

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•	Depreciation, depletion and amortization increased due to additional assets placed into service after the 2010 period,

•	Operating supplies and maintenance costs per ton sold were higher due to additional roof control costs, additional maintenance costs and equipment overhaul costs,

•	Higher costs associated with the increased sales price of coal sold, such as royalties and production related taxes,

•	Increased actuarial expenses related to other post employment benefits and pension related to employees retiring sooner than originally anticipated and average claim costs being higher than originally anticipated, and

•	Increased labor and labor related charges as a result of additional employees, increased overtime hours worked and the impact of the $1.50 per hour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related to the new UMWA contract.

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•	Employee wages and related expenses increased $8 million which was primarily attributable to the support staff retained in the Dominion Acquisition and additional hiring of support staff in the period-to-period comparison.

•	Advertising and promotion expense increased $5 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.

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

•	Commission expense increased $1 million due to the increase in average sales price and additional tons sold for which a third party was owed a commission in the period-to-period comparison.

•	Consulting and professional services increased $1 million due to various transactions that occurred throughout both

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•	Miscellaneous selling, general and administrative expenses increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.

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Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers.

•	Average preparation costs per ton sold increased due to additional maintenance projects completed at our preparation plants in the period-to-period comparison.

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Labor and related benefits were impaired on a cost per ton sold basis due to higher costs and lower volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement. Contributions are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Additional employees in the period-to-period comparison also contributed to higher labor costs. Non-union benefit rates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing

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•	Production taxes average cost per ton sold increased primarily due to the $4.79 per ton higher average sales price.

•	Average operating costs per steam ton sold increased due to lower tons sold as fixed costs were allocated over less tons; therefore, unit cost increased.

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•	Average operating costs per ton sold increased due to the mix of mines selling coal on the high volatile metallurgical coal market. As higher cost structure mines sell coal in the high volatile metallurgical market, average operating costs per ton sold increase. Previously, this segment only included lower cost structure mines.

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Labor and related benefits increased due to higher employee counts, higher non-union benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher labor and related costs were also due to higher non-union benefit rates for active employees related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the steam coal segment. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the new collective bargaining agreement, in the period-to-period comparison. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the steam coal segment. Increased labor and related benefit costs per unit sold were also offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.

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Average operating supplies & maintenance costs per ton sold increased due to additional maintenance and equipment overhaul costs and additional roof control costs. Additional maintenance and equipment overhaul costs were related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison.

•	Average coal preparation costs per ton sold increased due to additional maintenance projects that have been completed

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•	Production taxes average cost per ton sold increased due to the $5.10 per ton higher average sales price.

•	In-transit charges average cost per ton sold increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the mix of mines now shipping high volatile metallurgical coal.

•	Subsidence costs per ton sold increased due to more structures and higher costs related to these structures that were impacted by longwall mining in the period-to-period comparison. Subsidence costs also increased due to an increase in the length of streams that were impacted by longwall mining in the period-to-period comparison.

•	Average operating costs per ton sold decreased due to higher tons sold. Therefore, fixed costs were allocated over more tons; therefore, unit costs decreased.

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Average operating supplies and maintenance costs per ton sold increased due to additional roof control costs, additional ventilation costs of coalbed methane gas and additional equipment overhaul costs. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of support put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due to higher steel prices in the period-to-period comparison. Additional costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period.

•	Costs associated with the sales price of coal sold, such as royalties and production related taxes, increased due to the higher average sales prices received for low volatile metallurgical coal in the period-to-period comparison.

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•	Abandonment of long-lived assets was $116 million for the nine months ended September 30, 2011 as a result of the decision to permanently idle Mine 84.

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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 in freight revenue. The increase was primarily due to the 2.7 million ton increase in export tons in the period-to-period comparison.

•	Purchased coal costs increased approximately $29 million in the period-to-period comparison primarily due to differences in the quality of coal purchased, increases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.

•	Coal contract buyout costs increased $5 million as a result of a lower priced coal sales contract being bought out in order to sell the tons on a higher priced contract in a future period.

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Closed and idle mine costs decreased approximately $104 million in the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia was increased $82 million. Also in the 2010 period, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine was abandoned. In addition, $8 million of reduced expenses were recognized in closed and idle mine costs for various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individually material

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Litigation expense of $25 million was recognized in the nine months ended September 30, 2010 related to an anticipated legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized in the nine months ended September 30, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million.

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Other expenses related to the coal segment were $12 million higher for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. The increase was related to a $5 million charge for an additional liability due to Pennsylvania stream remediation and $7 million of the increase was related to various transactions that occurred throughout both periods, none of which were individually material.

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•	Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.

•	The short-term incentive compensation program is designed to increase compensation to eligible employees when

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•	Contract buyout represents the cancellation of a drilling arrangement with a third party well driller.

•	Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of the Dominion Acquisition as well as an increase in total CONSOL Energy stock-based compensation expense. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.

•	Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.

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Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest and during the 2011 period de-consolidated the impact of this third party due to the cancellation of the drilling arrangement. Based on analysis, during the time CONSOL Energy guaranteed the bank loans the entity held, it was determined that CONOL Energy was the primary beneficiary. Therefore, the entity was fully consolidated and the earnings impact is fully reversed in the non-controlling interest line discussed below.

•	Legal fees for the 2010 period were related to the special committee formed during the CNX Gas take-in transaction and also represent legal fees related to the shareholder litigation related to this transaction.

•	Other corporate related expense decreased $2 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Interest expense increased $49 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition in April 2010.

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On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.

•	Evaluation fees for non-core asset dispositions increased $3 million in the period-to-period comparison due to various corporate initiatives that began in the 2010 period.

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Transaction and financing fees of $61 million incurred in the nine months ended September 30, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion. Transaction and financing fees of $15 million incurred in the nine months ended September 30, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.

•	Bank fees increased $3 million in the period-to-period comparison due to the refinancing and extension of the previous $1.0 billion credit facility to $1.5 billion on May 7, 2010.

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

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Operating cash flow increased $183 million in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-period comparison. The 2011 net income included an approximately $75 million reduction due to the abandonment of Mine 84 which is discussed further in Note 8—Property, Plant and Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q. This reduction did not have a corresponding reduction to cash flows from operating activities because it was primarily related to the write-down of assets remaining at Mine 84 at the time of the abandonment, not cash obligations.

•	Operating cash flows increased $35 million in 2011 compared to the prior year due to differences in accrued income tax liabilities. The decrease in accrued income taxes in 2011 was $4 million compared to a decrease in accrued income taxes in the 2010 period of $39 million.

•	Operating cash flows increased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years, none of which were individually material.

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•	On April 30, 2010, CONSOL Energy paid $3.474 billion for the Dominion Acquisition. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

•	On May 28, 2010, CONSOL Energy paid $991 million to acquire the shares of CNX Gas common stock and vested stock options which it did not previously own.

•	On September 30, 2011, CONSOL Energy received net proceeds of $519 million related to the Noble transaction. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

•	On September 30, 2011, CONSOL Energy received a $67 million cash distribution from CONE Gathering LLC. See Note 2—Acquisitions and Dispositions, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

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Total capital expenditures increased $176 million to $997 million in the nine months ended September 30, 2011 compared to $822 million in the nine months ended September 30, 2010. Capital expenditures for the gas segment increased $243 million due to the additional drilling in the period-to-period comparison. The increased gas segment capital was primarily due to the increased Marcellus Shale drilling. Capital expenditures for coal and other activities decreased $67 million in the period-to-period comparison. Face extension projects at various locations were lower by $83 million as a result of the majority of these projects being completed during the 2010 period, $13 million was incurred in the 2010 period as a result of a longwall shield lease buyout, and the 2011 period was lower by approximately $29 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011 and an approximate $18 million decrease in 2011 related to various other equipment expenditures throughout both periods. These reductions in coal and other capital were offset, in part by an approximate $61 million increase in expenditures related primarily to the ongoing development of the BMX Mine which is scheduled to go on-line in 2014, and a $15 million increase in 2011 related to the construction of the Northern West Virginia RO system.

•	Proceeds of $2.75 billion were received on April 1, 2010 in connection with the issuance of $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.

•	In 2010, proceeds of $1.83 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.

•	In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility. In 2010, CONSOL Energy received proceeds of $150 million under this facility.

•	In 2011, CONSOL Energy paid $266 million, including a make-whole provision, to redeem the 7.875% notes that were due in March 2012.

•	In 2011, CONSOL Energy paid $15 million related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020, and 6.375% Senior Notes due 2021. See Note 10—Long-Term Debt, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

•	In 2011, CONSOL Energy paid outstanding borrowings of $155 million under the revolving credit facility. In 2010, CONSOL Energy paid $279 million under this facility.

•	Dividends of $68 million were paid in 2011 compared to $63 million in 2010. The increase was due to the 44.3 million additional shares issued on March 31, 2010.

•	In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior unsecured notes due in March 2021.

•	In 2011, CNX Gas, a wholly-owned subsidiary, paid outstanding borrowings of $129 million under its revolving credit facility compared to receiving $20 million in 2010.

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(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 2011 contributions are expected to approximate $71.7 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.

•	An aggregate principal amount of $1.5 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.

•	$32 million in advance royalty commitments with an average interest rate of 7.56% per annum.

•	An aggregate principal amount of $64 million of capital leases with a weighted average interest rate of 6.46% per annum.

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•	deterioration in 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 prices we receive for our coal and 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 gas to market;

•	a loss of our competitive position because of the competitive nature of the coal and 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;

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•	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, as well as the impact of any adopted regulations on our coal mining operations due to the venting of coalbed methane which occurs during mining;

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

•	the risks inherent in coal and 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;

•	our focus on new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

•	decreases in the availability of, or increases in, the price of commodities and services used in our mining and gas operations, as well as our exposure under “take or pay” contracts we entered into with well service providers to obtain services which if not used could impact our cost of production;

•	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 gas operations;

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

•	costs associated with perfecting title for coal or gas rights on some of our properties;

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

•	the impacts of various asbestos litigation claims;

•	increased exposure to employee related long-term liabilities;

•	increased 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;

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acquisitions and joint ventures that we recently have completed or entered into or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies or other benefits (including joint venture partners paying carry obligations), 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 anti-takeover effects of our rights plan could prevent a change of control;

•	increased exposure on our financial performance due to the degree we are leveraged;

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

•	our ability to acquire water supplies needed for gas drilling, or our ability to dispose of water used or removed from strata

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

•	other factors discussed in our 2010 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 4.	CONTROLS AND PROCEDURES

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ITEM 1.	LEGAL PROCEEDINGS

ITEM 1A.	RISK FACTORS

•	variations in thickness of the layer, or seam, of coal;

•	amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	weather conditions; and

•	security breaches or terroristic acts.

•	unexpected drilling conditions;

•	title problems;

•	pressure or irregularities in geologic formations;

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	adverse weather conditions;

•	reductions in natural gas prices;

•	security breaches or terroristic acts;

•	pipeline ruptures;

•	surface spillage of, or contamination of groundwater by, fracturing fluids used in hydraulic fracturing operations; and

•	unavailability or high cost of drilling rigs, other field services and equipment.

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•	uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;

•	the potential loss of key customers, management and employees of an acquired business;

•	the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;

•	problems that could arise from the integration of the acquired business;

•	unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion of the acquisition opportunity; and

•	we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.

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ITEM 5.	OTHER INFORMATION

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(1)	MSHA assigns an identification number to each coal mine and may or may not assign separate identification numbers to related facilities such as preparation plants. We are providing the information in the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.

(2)

We have not included currently closed or idled mines in the above table. Our closed and/or idled mines received one Mine Act section 104 Significant & Substantial citations in the three months ended September 30, 2011. Total proposed assessments were $102 in the three months ending September 30, 2011. There were 13 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of September 30, 2011 for our closed and/or idle mines. These actions may have been initiated in prior quarters.

(3)	Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.

(4)	Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.

(5)	Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(6)	Includes proposed MSHA assessments received during the three months ended September 30, 2011 for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7)

Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.

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(1)	MSHA assigns an identification number to each coal mine and may or may not assign separate identification numbers to related facilities such as preparation plants. We are providing the information in the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.

(2)

We have not included currently closed or idled mines in the above table. Our closed and/or idled mines received six Mine Act section 104 Significant & Substantial citations in the nine months ended September 30, 2011. Total proposed assessments were $136 in the nine months ending September 30, 2011. There were 13 legal actions in total pending before the Federal Mine Safety and Health Review Commission as of September 30, 2011 for our closed and/or idle mines. These actions may have been initiated in prior quarters.

(3)	Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.

(4)	Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.

(5)	Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(6)	Includes proposed MSHA assessments received during the nine months ended September 30, 2011 for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7)

Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.

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ITEM 6.	EXHIBITS

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