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ITEM 1.	CONDENSED FINANCIAL STATEMENTS

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(A)	Included in the Coal segment are sales of $129,014 to First Energy which comprises over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $1,298, $2,503 and $3,772 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $19,750, $135,048 and $58,910 for Coal, Gas and All Other, respectively.

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

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(J)	Included in the Coal segment are sales of $539,568 to Xcoal Energy & Resources comprising over 10% of sales

(K)	Includes equity in earnings of unconsolidated affiliates of $13,544, $1,694 and $4,751 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 30, 2012, CONSOL Energy Inc. issued notice under the Worker Adjustment and Retraining Notification Act (WARN) of its intent to idle its Miller Creek surface operations near Naugatuck, W. Va., resulting in a layoff impacting approximately 145 employees. Production from the Miller Creek surface operations was 1.2 million tons for the nine months ended September 30, 2012. The idling of the Miller Creek operations is due to a sequence of permit delays that has prevented the company from securing all of the necessary environmental permits required to continue mining as identified in the company's mine plan.

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In June 2012, CONSOL Energy announced that it acquired a non controlling interest in Epiphany Solar Water Systems, a privately-held company founded in New Castle, PA in 2009. Epiphany Solar Water Systems is testing what is believed to be the world's first concentrated solar powered water purification system. Under the agreement, CONSOL Energy has made an initial investment of $0.5 million and one of its Marcellus gas well locations in Greene County will serve as the site to pilot test this solar powered water purification system. The pilot test began in July with initial results expected in before the end of the year.

•	In June 2012, CONSOL Energy sold its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for $170 million in cash to Cloud Peak Energy. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal. This transaction resulted in a pre-tax gain of $151 million.

•	In June 2012, CONSOL Energy expanded an existing mining joint venture with a privately-held company in Central Pennsylvania. The joint venture will self-fund, through retained earnings, a $54 million (gross) expansion in 2012 and

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In April 2012, CONSOL Energy announced certain changes to the salaried other post-retirement benefit plan that current retirees and current active employees will receive as of January 1, 2014. The change provides a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B and Part D premiums and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug coverage. Employees who work or worked in corporate or operations support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefit. CONSOL Energy remeasured the salaried other postretirement plan as of March 31, 2012 to recognize these changes. The remeasurement reflects the reduction in benefits and the change in discount rate from 4.51% at December 31, 2011 to 4.57% at March 31, 2012. The remeasurement resulted in a reduction of approximately $80.6 million of Other Post-Retirement Benefits (OPEB) liability with a corresponding offset to Other Comprehensive Income, net of applicable deferred taxes. The change resulted in a $6.3 million reduction in OPEB expense compared to what was originally expected to be recognized for the nine months ended September 30, 2012. Additionally, the change will result in a $3.1 million reduction to OPEB expense compared to what was originally expected to be recognized for the remaining three months of 2012. The change was made to align CONSOL Energy's corporate and operational support compensation package more closely with our peer group.

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Pennsylvania enacted Act 13 of 2012, which provides for the comprehensive regulation of Marcellus Shale development in Pennsylvania. Among other things, Act 13 requires an impact fee be paid annually on all nonconventional gas wells drilled in the state. The annual fee is based on annual average sales price and is modified annually for a 15-year period for each well. The impact fee also required the first year fee be paid on all applicable wells drilled before January 1, 2012 with subsequent annual fees to apply each year thereafter. CONSOL Energy's retroactive impact fee related to wells drilled prior to January 1, 2012 was approximately $4 million. This amount was paid in September 2012.

•	In April 2012, CONSOL Energy sold its non-producing Elk Creek reserves in southern West Virginia. The transaction resulted in cash proceeds of $26 million and a gain on sale of assets of $11 million. In February 2012, CONSOL Energy sold it's non-producing Burning Star #4 reserves in Illinois. The transaction resulted in cash proceeds of $13 million and a gain on sale of assets of $11 million.

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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, synthetic rubber and steel that we use in our operations (although prices for some of these commodities declined during the quarter from previous quarters), (ii) increased scrutiny of existing safety regulations and the development of new safety regulations and (iii) additional environmental restrictions.

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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. For example, we entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved chlorides in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million.  The new facility must be placed into service no later than May 2013.

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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.  Another example is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011.  The 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

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In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide emissions from coal powered electric generating units.  The public comment period has run and publication of the final rules is expected soon. 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.

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On May 25, 2012, CONSOL Energy received a citizens' Notice of Intent to Sue from the Sierra Club, the Ohio Valley Environmental Coalition and the West Virginia Highlands Conservancy alleging violations of the Clean Water Act relating to selenium at its Fola mining complex in central West Virginia. On June 5, 2012, the West Virginia Department of Environmental Protection issued an Administrative Order to Fola. Fola is complying with the Administrative Order. On September 4, 2012, the citizens group filed a complaint against Fola in the U.S District Court for the Southern District of West Virginia covering the same matters addressed in the State Administrative Order.

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In late June, 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 East 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.

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

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•	Average cost of goods sold per ton increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.

•	Average labor and labor-related costs per ton sold increased as a result of the impact of the $1.00 per hour worked United Mine Workers of America (UMWA) contract wage increases, offset, in part, by fewer hours worked.

•	Average depreciation, depletion and amortization per ton sold increased due to additional assets placed into service after the 2011 period.

•	Average retirement and disability costs per ton sold decreased due to the improvement in other postretirement benefits discussed in the long-term liabilities section below.

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•	Lower lifting costs that were the result of decreased road maintenance, decreased well fishing and well tending costs.

•	Lower units-of-production depreciation, depletion and amortization rates for producing properties. These rates were generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. Increased proved and proved developed reserves relative to the net book value of the producing assets resulted in a lower units-of-production rate.

•	Lower direct administrative, selling and other costs per unit attributable to decreased actual dollars as a result of a reduction in direct administrative labor and other costs.

•	Gathering costs increased in the period-to-period comparison due to increased transportation charges.

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Employee wages and related expenses decreased $3 million in the period-to-period comparison primarily attributable to lower salary other post-retirement benefit expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions. Additionally, an other post employment benefit plan modification for certain salaried employees lowered expenses.

•	Consulting and professional services decreased $1 million in the period-to-period comparison primarily due to a reduction in CONSOL Energy's advertising and promotion campaign.

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

•	Miscellaneous general and administrative expenses were consistent in the period-to-period comparison due to various corporate projects that occurred throughout both periods, none of which were individually material.

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

•	Labor and related benefits average costs per thermal ton produced increased. This was primarily due to the impact of the wage increases of $1.00 per hour worked related to the UMWA collective bargaining agreement in the period-to-period comparison, offset, in part, by fewer overtime hours worked.

•	Various other unit costs including supplies, maintenance, power and miscellaneous costs did not significantly change individually or in total.

•	Subsidence average cost per thermal ton produced is lower in the period-to-period comparison due to the timing and quantity of structures undermined. Also, subsidence expense is lower in the current period due to less streams being undermined compared to the prior year quarter.

•	Unit costs were also improved due to various other items, none of which were individually material.

•	Average direct service costs to operations were impaired due to lower thermal tons produced in the period-to-period comparison which negatively impacted unit costs.

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•	Bailey Belt Incident costs represent expenses for various projects that were incurred during the belt-reconstruction period related to continued advancement of the mines and on-going projects at the mines.

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Closed and idle mine costs increased approximately $17 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.  Closed and idle mine costs increased $11 million due to the decision to idle operations at Fola Surface and $7 million due to the decision to idle operations at Buchanan Mine during September 2012. Closed and idle mine costs decreased $1 million due to other changes in operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.

•	Purchased coal costs increased approximately $1 million in the period-to-period comparison due to various items, 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 decreased $33 million primarily due to decreased shipments on contracts for which CONSOL Energy contractually provides transportation services.

•	Other expenses related to the coal segment increased $2 million in the period-to-period comparison due to various transactions which occurred throughout both periods, none of which were individually material.

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•	Lease Expiration costs were consistent in period-to-period comparison. Lease expiration costs relate to locations where CONSOL Energy allowed primary term leases to expire.

•	Dry Hole Costs decreased $2 million due to additional dry hole wells in the 2011 period. There were no dry hole costs incurred during the three months ended September 30, 2012.

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

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

•	Short-term incentive compensation decreased $1 million 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, environmental compliance, production, and unit costs.

•	Stock-based compensation decreased $1 million in the period-to-period comparison due to various activity in share-based compensation programs, none of which were individually material.

•	Unutilized firm transportation costs represent excess pipeline transportation capacity that the gas division obtained to enable gas production to flow on an uninterrupted basis as sales volumes increase. These costs remained consistent in the period-to-period comparison.

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

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

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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 loss on extinguishment of debt was $15 million, which primarily represented the interest that would have been paid on these notes if held to maturity.

•	Interest expense decreased $4 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period. These decreases were offset by an increase in uncertain tax positions interest expense.

•	Bank fees decreased $3 million due to lower borrowings on the revolving credit facilities in the period-to-period comparison.

•	Evaluation fees for non-core asset dispositions and other legal charges increased $1 million in the period-to-period comparison due to various corporate initiatives that were completed in 2011.

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

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•	Average cost of goods sold per ton sold increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.

•	The idle longwalls at the Blacksville Mine and the Buchanan Mine during March and April 2012 resulted in an increase in unit costs of approximately $1.32 per ton as the fixed costs were allocated over fewer tons.

•	Average operating supplies and maintenance costs per ton sold increased due to additional equipment maintenance, timing of major equipment overhaul costs, increased fuels and lubricants and use of pumpable cribs for roof support.

•	Average labor and labor related expenses per ton sold increased primarily as a result of the impact of the UMWA contract wage increases, offset, in part, by lower overtime.

•	Average depreciation, depletion and amortization per ton sold increased due to additional assets placed into service after the 2011 period.

•	Average retirement and disability costs per ton decreased due to the improvement in other postretirement benefits discussed in the long-term liabilities section below.

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•	Higher volumes in the period-to-period comparison due to the on-going drilling program, offset, in part, by 10.7 billion cubic feet divested in the 2011 Noble and 2011 Antero transactions resulted in lower average costs per thousand cubic feet sold. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

•	Lower units-of-production depreciation, depletion and amortization rates for producing properties. These rates were generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. Increased proved and proved developed reserves relative to the net book value of the producing assets resulted in a lower units-of-production rate.

•	Lower direct administrative, selling and other costs per thousand cubic feet sold due to increased sales volumes and decreased actual dollars as a result of lower direct administrative labor and other costs.

•	Gathering costs increased in the period-to-period comparison due to higher transportation charges.

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•	Employee wages and related expenses decreased $5 million primarily attributable to lower salary OPEB expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions, and a modification to the benefit plan for certain salaried employees.

•	Consulting and professional services decreased $3 million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising and promotion campaign.

•	Contributions decreased $4 million in the period-to-period comparison due to various transactions, none of which were individually material.

•	Miscellaneous general and administrative expenses decreased $2 million in the period-to-period comparison due to various transactions, none of which were individually material.

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

•	The Blacksville No. 2 longwall idling resulted in higher direct operating costs per ton produced. The mine continued to run the continuous miners and perform mine maintenance during the month of April when the longwall was idled for market reasons, which negatively impacted unit costs.

•	Labor and related benefits average costs per thermal ton produced increased. This was primarily due to the impact of the wage increases per hour worked related to the United Mine Workers of America (UMWA) collective bargaining agreement in the period-to-period comparison, offset, in part, by fewer overtime hours worked.

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Average operating supplies and maintenance costs per ton increased due to additional maintenance and equipment overhaul costs and additional contractor labor, combined with lower tons produced.  Additional maintenance and equipment overhaul costs are related to additional equipment being service in the current year-to-date period.  Additional contractor labor costs resulted from additional underground hourly contractors utilized as well as additional security contractor costs in the current year.

•	There were no significant changes in various other unit costs individually or in total.

•	Average direct service costs to operations were impaired due to lower tons produced in the period-to-period comparison.

•	Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds and ditches, and additional permits for water discharge pipelines.

•	Selling expense decreased in the period-to-period comparison due to fewer tons being sold under contracts that require commissions.

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•	Average operating costs per high volatile metallurgical ton increased due to fewer tons produced. Fixed costs are allocated over less tons, resulting in higher unit costs.

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Mine maintenance and supplies per ton produced increased due to the mix of mines producing tons that were shipped as high volatile metallurgical coal. Mines with higher cost structures produced a larger portion of the high volatile metallurgical coal shipped in the current year-to-date period compared to the prior year-to-date period. This was primarily due to the Bailey belt incident previously discussed.

•	Labor and related benefits average costs per high volatile metallurgical ton produced decreased due to less overtime worked, offset, in part, by lower tons produced and higher hourly wage rates.

•	Various other unit costs including power and miscellaneous costs did not change significantly individually or in total.

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•	The Buchanan longwall was idled during the months of March and April which resulted in $10.59 per ton higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the month when the longwall was idled. This negatively impacted unit costs.

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Low volatile metallurgical coal production was 3.0 million tons in the nine months ended September 30, 2012 compared to 4.3 million tons in the nine months ended September 30, 2011. Production was significantly lower in the period-to-period comparison due to the Buchanan Mine being idled in early September 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Fixed costs were then spread over fewer tons produced which increased all costs on a per unit basis.

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Gain on sale of assets attributable to the Other Coal segment were $181 million in the nine months ended September 30, 2012 compared to $5 million in the nine months ended September 30, 2011. The change was primarily related to 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. 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.

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In the nine months ended September 30, 2012, $12 million of income was recognized related to contracts from certain thermal coal customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended September 30, 2011.

•	In the nine months ended September 30, 2011, a gain of $10 million was recognized for the issuance of a pipeline right-of-way to a third party. There were no such transactions in the nine months ended September 30, 2012.

•	Equity in earnings of affiliates decreased $6 million due to lower earnings from our equity affiliates.

•	Abandonment of long-lived assets were $116 million for the nine months ended September 30, 2011 as a result of the 2011 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 by freight revenue. The decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.

•	Purchased coal costs decreased approximately $25 million in the period-to-period comparison primarily due to coal purchases to fulfill various contracts during a railroad bridge outage that occurred in the 2011 period.

•	PA Streams costs were $5 million for the nine months ended September 30, 2011 as a result of the recognition of an additional liability related to the environmental remediation of streams in Pennsylvania affected by our mines.

•	Coal contract buyout costs decreased $5 million as a result of a lower priced coal sales contract being bought out in 2011 in order to sell the tons on a higher priced contract.

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Closed and idle mine costs increased approximately $32 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  The increase was the result of $36 million additional costs related to reclamation liabilities and on-going idling costs incurred at the Fola Complex in the nine months ended September 30, 2012.  Closed and idle mine costs increased $8 million as the result of a 2012 decision to temporarily idle Buchanan Mine in 2012.  Closed and idle mine costs increased $4 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. Closed and idle mine costs decreased $16 million as the result of a 2011 decision to permanently abandon Mine 84 in 2011.

•	Bailey Belt Incident costs represents expenses during the belt-reconstruction period related to continued advancement of the mines and on-going projects at the mines

•	Other expenses related to the coal segment remained consistent for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

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•	Lease Expiration costs increased $12 million due to various lease expirations relating to locations where CONSOL Energy allowed primary lease terms to expire.

•	Dry Hole Costs increased $5 million primarily due to a favorable settlement involving defective pipe in 2011 which reduced expenses in the nine months ended September 30, 2011.

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

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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.

•	Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of 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.

•	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 higher for the 2012 year-to-date period compared to the 2011 year-to-date period due to the projected higher payouts.

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

•	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 $2 million decrease is due to increased utilization of pipeline capacity in the 2012 period.

•	Other corporate related expense increased $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 decreased $17 million in the period-to-period comparison. Interest expense decreased due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $283 million in the period-to-period comparison.

•	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 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.

•	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 decreased $6 million due to lower borrowings on the revolving credit facilities in the period-to-period comparison.

•	Evaluation fees for non-core asset dispositions and other legal charges decreased $1 million in the period-to-period comparison due to various corporate initiatives that began after 2010.

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

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•	Operating cash flow decreased $722 million in 2012 due to lower net income in the period-to-period comparison.

•	Operating cash flows decreased 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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Total capital expenditures increased $155 million to $1,152 million in the nine months ended September 30, 2012 compared to $997 million in the nine months ended September 30, 2011. Capital expenditures for coal and other activities increased $283 million in the period-to-period comparison. The ongoing development and expenditures of the BMX mine, which is scheduled to go on-line in 2014, increased $51 million in the period-to-period comparison. Capital expenditures for the Northern West Virginia RO system increased $71 million in the period-to-period comparison. In the nine months ended September 30, 2012 capital expenditures related to long wall roof shields increased $70 million in the period-to-period comparison. The remaining $91 million increase was due to various projects throughout both periods, none of which were individually material. Capital expenditures for the gas segment decreased $128 million primarily due to a decrease in CBM drilling and gathering system expenditures in the period-to-period comparison.

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Proceeds from the sale of assets decreased $111 million in the period-to-period comparison. The decrease was due to $344 million received on September 30, 2012 related to the Noble Transaction compared to $489 million in net proceeds related to the Noble Transaction received on September 30, 2011. On September 21, 2011, CONSOL Energy sold an overriding royalty to Antero Resources Appalachian Corp. for $190 million of net proceeds. These decreases were offset, in part, by the sale of non-producing Northern Powder River Basin (PRB) assets on June 29, 2012, which resulted in proceeds of $170 million. Also, the sale of various other properties in 2012 which resulted in proceeds of $39 million. The remaining $15 million period-to-period increase was from various other transactions that occurred throughout both periods, none of which were individually material. See Note 2 -

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Distributions From, net of (Investments In), Equity Affiliates decreased $90 million in the period-to-period comparison. During the 2012 period, $35 million was contributed to CONE in order to meet the operating and capital expenditure needs of the joint venture. The joint venture, of which CONSOL Energy owns 50%, was established on September 30, 2011 to develop and operate the gas gathering system in the Marcellus Shale play. On September 30, 2011, CONSOL Energy received a $68 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. The remaining $13 million increase was primarily due to additional cash distributions received from various Equity Affiliates in the period-to-period comparison.

•	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, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility.

•	In 2011, CONSOL Energy paid outstanding borrowings of $284 million under the revolving credit facilities.

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

•	Dividends of $85 million were paid in 2012 compared to $68 million in 2011. This is due to the increase of the quarterly dividend by 25%, or $0.025 per share, to $0.125 per share in the 2012 period.

(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 2012 contributions are expected to approximate $110 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.

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•	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% senior unsecured notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.

•	An aggregate principal amount of $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.

•	An aggregate principal amount of $6 million on other various rate notes maturing through June 2031.

•	$31 million in advance royalty commitments with an average interest rate of 6.73% per annum.

•	An aggregate principal amount of $61 million of capital leases with a weighted average interest rate of 6.36% per annum.

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•	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;

•	a significant or extended decline in 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;

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•	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;

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

•	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;

•	our accruals for obligations for long-term employee benefits are based upon assumptions which, if inaccurate, could result in our being required to expend greater amounts than anticipated;

•	due to our participation in an underfunded multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees and in the future we may have to make additional cash contributions to fund the pension plan or incur withdrawal liability;

•	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, 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 including joint venture partners paying anticipated carry obligations;

•	the terms of our existing joint ventures restrict our flexibility and actions taken by the other party in our gas joint ventures may impact our financial position;

•	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;

•	other factors discussed in our 2011 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

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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

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

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

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Of the approximately $3.3 billion we anticipate receiving from Noble Energy, approximately $2.1 billion depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $534 million of the total anticipated consideration of $594 million is dependent upon Hess paying carried costs.  Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period.  Moreover, the performance of these third party obligations is outside our control.  The inability or failure of a joint venturer to pay its portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by that joint venture;

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Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per million British thermal units or “MMBtu” in any three consecutive month period and will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months.  As a result of this provision, Noble Energy's obligation to pay carried costs was suspended beginning on December 1, 2011.  We cannot predict when this suspension will be lifted and Noble Energy's obligation to pay the carried costs will resume. This suspension has the effect of requiring us to incur our entire 50 percent share of the drilling and completion costs for new wells during the suspension period and delaying receipt of a portion of the value we expect to receive in the transaction.

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The Noble Energy joint development agreement prohibits prior to March 31, 2014, unless Noble Energy consents in its sole discretion, any transfer of our interests in the Noble Energy joint venture assets or our selling or otherwise transferring control of CNX Gas Company.  The Hess joint development agreement prohibits prior to October 21, 2014, unless Hess consents in its sole discretion, any transfer of our interests in the Hess joint venture assets.   These restrictions may preclude transactions which could be beneficial to our shareholders.

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

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Under the joint venture agreements, our joint venture partners have the right for a specified period of time to perform due diligence on the title to the oil and gas interests which we conveyed to them.  To the extent our joint venture partners assert claims for title defects, we have a specified period of time in which to review and respond to the asserted title defects, as well as to cure them. We are currently in the this review process with Noble and Hess. If Noble or Hess establish any title defects which are not resolved or if the subject acreage is reassigned to CONSOL, then subject to certain deductibles, their aggregate carried cost obligation under the respective joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the respective transactions. 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.

ITEM 6.	EXHIBITS

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