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ITEM 1.	CONDENSED FINANCIAL STATEMENTS

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

(E)	Includes equity in earnings of unconsolidated affiliates of $(3,504), $2,503 and $8,574 for Coal, Gas and All Other, respectively.

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(J)	Included in the Coal segment are sales of $409,745 to First Energy and $382,950 to Xcoal Energy & Resources each comprising over 10% of sales.

(K)	Includes equity in earnings of unconsolidated affiliates of $7,588, $6,484 and $8,604 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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•	In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24.7 million. The transaction resulted in a $15.3 million gain on the sale of assets.

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

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Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company's salary retirement pension plan exceeding the annual projected service and interest costs of the plan. The pension settlement resulted in a $38.5 million pre-tax expense adjustment. Many of the lump sum payments in the nine months ended September 30, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive Plan. Also, pension settlement required the pension plan to be remeasured using updated assumptions at September 30, 2013. The updated assumptions include resetting the discount rate used in the actuarial calculation. See Note 3 - Components of Pension and Other Post-Employment Benefit (OPEB) Plans Net

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A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the nine months ended September 30, 2013. As a result of the Company's review of the title defect notice, asserted by Noble, and working in collaboration with Noble, CONSOL Energy has addressed defects of $21.8 million. See Note 8 - Property, Plant and Equipment, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

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CNX Gas Company completed negotiations with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play.  CNX Gas Company paid $46.3 million as an up-front bonus payment at closing. Approximately 7.6% percent of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title.  CNX Gas Company must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas forgoes the bonus. Our joint venture partner, Noble Energy, has acquired 50% of the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costs in June 2013.

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On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County, Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified and containment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. This event resulted in a pre-tax expense of $38.6 million in the nine months ended September 30, 2013.

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In the nine months ended September 30, 2013, an agreement in principle was reached for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010 in principle. The total settlement provides for a payment to the plaintiffs of $42.73 million, of which the company expects to pay $19.2 million. On May 8, 2013, the parties executed and filed with the Court a stipulation and agreement of compromise and settlement. A settlement hearing was held by the Court on August 23, 2013, and the settlement was approved. See Note 11 - Commitments and Contingencies, in the Notes to the Unaudited Consolidated Financial Statements included in this Form 10-Q for additional details.

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

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

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

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

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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.  OSM has indicated that it will not issue a draft rule or a draft environmental impact statement until sometime in 2014.  Other examples are the Mercury and Air Toxic Standards (MATS) (remanded by the court and re-proposed by the EPA in November 2012) and the Utility Maximum Achievable Control Technology (Utility MACTS) rules issued by the EPA. These new regulations set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent New Source Performance Standards (NSPS) for particulate matter (PM), SO2 and NOx.  The EPA reconsidered the UMACT rules and recently finalized revised new source performance

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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 proposed rules would have applied to new power plants and to existing plants that make major modifications. If the rules had been adopted as proposed, the only new coal fired power plants that could have met the proposed emission limits would have been 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.  On September 20, 2013, EPA re-proposed NSPS for CO2 for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012. These proposed rules will also require CCS for new coal fired power plants.

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CONSOL Energy surface coal mining operations in West Virginia are subject to several citizen suits and several citizen groups' Notices of Intent to Sue relating to alleged violations of water discharge permits from our coal mining operations.  In each of these matters, CONSOL Energy investigates the complaints, if necessary develops and implements compliance plans, and defends the citizen suits as appropriate.

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

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•	Average cost of goods sold decreased due to additional tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

•	On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

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

•	Average direct operating costs were impaired due to CONSOL Energy entering into several new longwall leases in 2013 at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.

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•	Higher volumes in the period-to-period comparison, due to the on-going Marcellus drilling program, resulted in an overall improvement in unit costs. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

•	Lifting costs were improved on a unit basis due to the increase in volumes, offset by higher accretion expense related to the estimated well plugging liability and increased road repair and maintenance costs.

•	Depreciation, depletion and amortization was also improved due to the increase in volumes. This improvement was offset by higher units-of-production rates for producing properties.

•	The improvement in gathering costs on a unit basis, due to the increase in volumes, was offset by higher firm transportation costs and increased processing fees associated with natural gas liquids.

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

•	Employee wages and related expenses decreased $1 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit expenses (OPEB) in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.

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

•	Consulting and professional services increased $1 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which are individually significant.

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

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•	Average cost of goods sold decreased due to additional tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

•	As previously discussed, on July 27, 2012 a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

•	In response to weak market conditions for domestic coal, the annual miner's vacation period at Blacksville No. 2 and Robinson Run mines was extended for a period of two weeks in July 2012. These mines operated in the 2013 period which resulted in higher costs.

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

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Gain on sale of assets attributable to the Other Coal segment was $18 million in the three months ended September 30, 2013 compared to $1 million in the three months ended September 30, 2012. The increase of $17 million was primarily related to the 2013 sale of 1.5 MM tons of Pittsburgh 8 Coal that CONSOL Energy controlled in Belmont County, OH for a gain of $2 million and the 2013 sale of 50% interest in a joint venture in Alberta, Canada for a gain of $15 million. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of these sales.

•	Equity in earnings of affiliates decreased $3 million due to lower earnings from our equity affiliates.

•	For the three months ended September 30, 2012 there was $5 million of income from certain thermal coal contract buyouts. There were no corresponding transactions in three months ended September 30, 2013.

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

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

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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.

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Closed and idle mine costs decreased approximately $7 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Closed and idle mine costs decreased $8 million due to the decision to shutdown the Fola Mining Complex in August 2012 and $7 million due to the decision to idle operations at Buchanan Mine in September 2012. These decreases were offset, in part, by an increase of $8 million in costs incurred primarily by the Amonate complex.

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

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

•	Purchased coal costs increased $2 million due to higher amounts of coal that needed to be purchased to fulfill various contracts.

•	Other expenses related to the Other Coal segment decreased $9 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	There was an increase of $3 million related to increased earnings from our equity affiliates.

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

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

•	CONSOL Energy has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a book value to CONSOL Energy of $13 million for the three months ended September 30, 2013 compared to $2 million for the three months ended September 30, 2012.

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•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $2 million increase is due to a greater number of leases which CONSOL Energy choose to let expire in the current period when compared with the prior period.

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

•	Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The $8 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

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

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

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

•	Legal fees decreased $1 million due to various transactions, none of which were individually material.

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•	Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. See Note 8 - Property, Plant and

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

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

•	Interest expense decreased $1 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.

•	Other corporate items remained consistent in the period-to-period comparsion.

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•	Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

•	On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The mines operated in the 2013 period, which resulted in lower direct operating costs per ton produced.

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Direct operating costs improved primarily due to a decrease in all direct operating costs at the Blacksville No. 2 Mine which was the result of the mine being idled March 12, 2013 until May 20, 2013 due to a fire. Also, in March and April 2012, the Blacksville No. 2 Mine ran the continuous miners and worked on various projects, while the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.

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

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

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Depreciation, depletion and amortization was improved primarily due to lower production at Blacksville No. 2 Mine related to the mine being shut down in 2013 due to the fire, and due to the shutdown of operations at the Fola Mining Complex in August 2012. The improvements were offset, in part, by higher costs in the 2013 period due to the reduction in production at both the Bailey and Enlow Fork Mines in the 2012 period as a result of the structural failure and due to the idling of the Buchanan Mine in September 2012 in response to the weak world economy.

•	Average direct operating costs were impaired due to CONSOL Energy entering into several new longwall leases in 2013 at our Bailey Mine, Robinson Run Mine, and Shoemaker Mine.

•	Costs were impaired in the current period due to the idling of the Buchanan Mine in September 2012. Also, in March and April 2012, the Buchanan Mine ran the continuous miners and worked on various projects, but the longwall was idled resulting in higher 2012 unit costs. This did not occur in the 2013 period.

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

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

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

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

•	Employee wages and related expenses decreased $6 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan and lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison. The lower OPEB expenses relate to changes in the discount rates and other assumptions.

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

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

•	Consulting and professional services increased $6 million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which were individually significant.

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

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•	Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.

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•	On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. This resulted in lower direct operating costs in the 2013 period or an improvement in the period-to-period comparisons.

•	The Blacksville No. 2 Mine was idled in 2013 until May 20th due to the fire that was previously discussed. This resulted in a reduction in all direct operating costs in the current period, as well as a majority of the unit costs.

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

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

•	In response to weak market conditions for domestic coal, the annual miner's vacation period at Blacksville No. 2 and Robinson Run mines was extended for a period of two weeks in July 2012. This did not occur in the 2013 period.

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

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

•	Unit costs decreased due to the increase in production volumes since fixed costs are spread over more tons.

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

•	Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, which was discussed previously. The decrease in unit costs was also offset by the reduction in production tons.

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Gain on sale of assets attributable to the Other Coal segment was $46 million in the nine months ended September 30, 2013 compared to $181 million in the nine months ended September 30, 2012. The decrease of $135 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in income of $22 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in income of $25 million and the sale of 50% interest in a joint venture in Alberta, Canada that resulted in income of $15 million. See Note 2—Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional detail of these sales. The remaining $2 million decrease was related to various transactions that occurred throughout both periods, none of which were individually material.

•	Equity in earnings of affiliates decreased $1 million due to lower earnings from our equity affiliates.

•	In the nine months ended September 30, 2012, there was an additional $12 million in income that was related to certain thermal coal contract buyouts. There were no such items in the nine months ended September 30, 2013.

•	In the nine months ended September 30, 2013, $5 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyor accident. There is no assurance that additional proceeds from the incident will be received.

•	The remaining $1 million decrease in other income is 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 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.

•	Bailey Belt Incident costs represent expenses 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 decreased approximately $10 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.  There was a $20 million decrease due to the shutdown of the Fola Mining Complex in August 2012. This was offset by an increase in the reclamation liability at the Fola Mining Complex in the June 2012 period due to new regulatory requirements and water and selenium treatment estimates. The decrease was also offset, in part, by an increase of $7 million in costs incurred primarily by the Amonate Complex. The remaining increase of $3 million was due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.

•	General and Administrative Expense related to the other coal segment decreased by $5 million primarily due various transactions, none of which were individually material. Refer to the discussion of total general and administrative costs contained in the section "Net Income" of this quarterly report for detailed costs explanations.

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

•	Stock-based compensation was higher in the period-to-period comparison primarily due to additional non-cash amortization expense and accelerated non-cash amortization for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program.  The new program replaces several previously provided long-term

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

•	Other expenses related to the coal segment decreased $15 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	CONSOL Energy has substantially completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a book value to CONSOL Energy of $22

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•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $7 million decrease is due to CONSOL Energy allowing fewer leases to expire in the current period when compared with the prior period.

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

•	Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. . The $16 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

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

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

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

•	Legal fees expense decreased $1 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. Ongoing 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.

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

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

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The CNX Gas shareholder settlement is the result of an agreement in principle for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provides for a payment to the plaintiffs of $42.73 million, of which the Company expects to pay $18.8 million. This settlement is subject to court approval and to the execution of final agreements with the parties.

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Corporate initiative fees and other legal charges reflect various fees for services related to corporate initiatives to evaluate structure changes and various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas shareholder settlement case. See Note 8 - Property, Plant and Equipment and Note 11 - Commitments and Contingencies of the Notes to the Condensed Consolidated Financial Statements of this Form 10-Q for additional information.

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

•	Interest expense decreased $8 million primarily due to an increase in capitalized interest due to higher capital expenditures for major construction projects in the current period.

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

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•	Operating cash flow decreased $317 million in 2013 due to lower net income in the period-to-period comparison.

•	Operating cash flows increased $137 million in the period-to-period comparison due to changes in the gains on the sale of assets. See Note 2 - Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements for additional details.

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

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

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Coal segment capital expenditures decreased $187 million. The decrease was comprised of $69 million related to the completion of the Northern West Virginia RO system as well as a $27 million decrease in Bailey Mine Expansion projects. Longwall shield projects decreased $23 million as well as an additional $62 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material. Mineral lease expenditures associated with our advance mining royalties and leased coal assets also decreased $6 million in 2013.

◦	Gas segment capital expenditures increased $261 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions in Monroe and Noble Counties in Ohio, and various other individually insignificant projects;

◦	Other capital expenditures decreased $30 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•	Proceeds from the sale of assets increased $14 million in the period-to-period comparison due to:

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◦	$25 million received in August 2013 related to the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada;

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

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

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

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

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

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

◦	$13 million received in February 2012 related to the sale of the Burning Star No. 4 property; and

◦	$30 million decrease due to various other transactions that occurred throughout both periods, none of which were individually material.

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

•	Distributions from/investments in equity affiliates increased $1 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

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Restricted cash increased $56 million due to the release of $69 million of restricted cash of which $48 million is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012 and $21 million is associated with the Ryerson Dam Settlement. This was offset by the additional $12 million of restricted cash associated with the sale of the 50% interest in the CONSOL/Devon Energy joint venture in Alberta, Canada in August 2013.

•	In 2013, CONSOL Energy received $47 million of short term borrowings under the revolving credit facilities.

•	In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy repaid $7 million of borrowings.

•	The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in the first quarter of 2013. Dividends paid in the second and third quarter 2013 were $29 million and $28 million, respectively. This is compared to $85 million in dividends paid in the nine months ended September 30, 2012.

•	In 2013, CONSOL Energy received $7 million of borrowing under its Securitization Facility.

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

(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

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

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

•	An aggregate principal amount of $250 million of 6.375% notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.

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

•	Advance royalty commitments of $20 million with an average interest rate of 7.43% per annum.

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

•	An aggregate principal amount of $57 million of capital leases with a weighted average interest rate of 6.24% 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;

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

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

•	our reliance on major customers;

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

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

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

•	our inability to maintain satisfactory labor relations;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	the impacts of various asbestos litigation claims;

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

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

•	exposure to multi-employer pension plan liabilities;

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

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

•	acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated

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

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

•	risks associated with our debt;

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

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

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

•	the ability to obtain regulatory approvals for the transaction on the proposed terms and schedule; disruption to our business, including customer, employee and supplier relationships resulting from this transaction; risks that the conditions to closing may not be satisfied; and the impact of the transaction on our future operating results, our capital investment program, and our dividend; and

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

ITEM 6.	EXHIBITS

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