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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 natural gas and coal affecting our operating results and cash flows;

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

•	our reliance on major customers;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	the impacts of various asbestos litigation claims;

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

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

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

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

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

•	risks associated with our debt;

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

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

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

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

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

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

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ITEM 1.	Business

•	Total production of 472,274 Mcfe per day, an increase of 10% over 2012;

•	98% Natural Gas, 2% Liquids; and

•	34% Marcellus, 48% coalbed methane, 16% shallow oil & gas, 2% other.

•	5.7 Tcfe of proved reserves;

•	97.5% natural gas;

•	43.9% proved developed;

•	85.7% operated; and

•	A reserve life ratio of 33.25 years (based on fourth quarter 2013 production);

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•	Underground mining complexes are among the safest in the United States of America;

•	Production of 28.5 million tons of coal from continuing operations;

•	Coal reserve holdings of 3.0 billion tons;

•	30% of sales delivered to export markets;

•	59% of sales to domestic utilities; and

•	New BMX Mine in southwest Pennsylvania scheduled to come on-line in March 2014, as planned.

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•	Safety,

•	Compliance, and

•	Continuous Improvement.

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•	26 wells in Southwestern Pennsylvania,

•	10 wells in Central Pennsylvania,

•	10 wells in Northern West Virginia, and

•	71 wells drilled by Noble Energy in the wet gas area of the play.

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(1)

Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A. of this Form 10-K.

(2)

Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acres may include rights to multiple gas seams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acres in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.

(1)	Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various

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(a)	For additional information on our reserves, see “Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.

(1)

We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.

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(1)	The heat value shown for Assigned Operating reserves is based on the quality of coal mined and processed during the year ended December 31, 2013. The heat value shown for accessible reserves are based on as received, dry values obtained from drill hole analysis prorated by the associated Assigned Operating reserve values to account for similar mining and processing methods.

(2)

Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.

(3)	A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.

(4)	The table excludes 57 million tons of recoverable reserves which represents CONSOL Energy's portion of tonnage held by two equity affiliates. CONSOL Energy owns a 49% interest in both of these affiliates.

(1)

The heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use are used for these estimates. The heat value estimates for the Illinois Basin, unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.

(2)

Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are only reported for those coal seams that are controlled by ownership or leases.

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•	Fixed price contracts with pre-established prices;

•	Periodically negotiated prices that reflect market conditions at the time;

•	Price restricted to an agreed-upon percentage increase or decrease; or

•	Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices.

•	the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and

•	environmental and government regulation;

•	coal quality;

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•	transportation costs from the mine to the customer;

•	the reliability of fuel supply;

•	worldwide demand for steel;

•	natural/weather disasters; and

•	political changes in international governments.

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•	the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;

•	the purchase and installation of electronic communication and personal tracking devices underground;

•	the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;

•	the replacement of existing seals in worked-out areas of mines with stronger seals;

•	the purchase of new fire resistant conveyor belting underground;

•	additional training and testing that creates the need to hire additional employees; and

•	more stringent rock dusting requirements.

•	current and former coal miners totally disabled from black lung disease;

•	certain survivors of a miner who dies from black lung disease or pneumoconiosis; and

•

a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

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ITEM 1A.	Risk Factors

•	demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;

•	demand for metallurgical coal depends on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our thermal coal as higher-priced high volatile metallurgical coal;

•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable securitization facility may decline;

•	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our gas or coal reserves; and

•	our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

•	the overall domestic supply of natural gas;

•	the supply of natural gas in our market;

•	changes in the consumption pattern of industrial consumers, electricity generators and residential users;

•	weather conditions;

•	proximity and capacity of gas pipelines and other transportation facilities;

•	overall domestic and global economic conditions;

•	the price and availability of alternative fuels, especially thermal coal; and

•	the price and supply of imported liquefied natural gas.

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•	overall domestic and global economic conditions, technological advances affecting energy consumption, price and availability of foreign coal, and domestic and foreign government regulations;

•	the consumption pattern of industrial consumers, electricity generators and residential users;

•	weather can impact thermal coal demand (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);

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the price and availability of alternative fuels for electricity generation, especially natural gas (for example, abundant natural gas supplies at prices averaging less than $3/MMbtu during 2012 depressed the demand for thermal coal as natural gas fired electricity generation market share increased from approximately 25% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 42% in 2011 to 37% in 2012); and

•	increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate product produced from metallurgical coal, decreases the demand for metallurgical coal.

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•	unexpected drilling conditions;

•	title problems;

•	pressure or irregularities in geologic formations;

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	adverse weather conditions;

•	reductions in natural gas prices;

•	security breaches or terroristic acts;

•	pipeline ruptures;

•	lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;

•	environmental contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the environment resulting from our use of such fluids; and

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

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

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

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	weather conditions; and

•	security breaches or terroristic acts.

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•	geological conditions;

•	changes in governmental regulations and taxation;

•	the amount and timing of actual production;

•	assumptions governing future prices;

•	future operating costs; and

•	capital costs of drilling, completion and gathering assets.

•	geological conditions;

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

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

•	assumptions governing future prices; and

•	future operating costs, including the cost of materials.

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•	postretirement medical and life insurance ($1.0 billion);

•	coal workers' black lung benefits ($121.2 million);

•	salaried retirement benefits ($43.8 million); and

•	workers' compensation ($85.1 million).

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

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

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

•	the potential revision of assumptions regarding gas reserves as we acquire more knowledge by operating an acquired gas business;

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

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

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

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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.

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•	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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Approximately $1.9 billion of consideration that we expect to receive from Noble Energy depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $335 million of consideration that we expect to receive from Hess is dependent upon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control.  The inability or failure of 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.

•

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.

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

•	limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;

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

•	placing us at a competitive disadvantage compared to less leveraged competitors.

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•	our production is less than expected;

•	the counterparties to our contracts fail to perform the contracts; or

•	the creditworthiness of our counterparties or their guarantors is substantially impaired.

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ITEM 1B.	Unresolved Staff Comments

ITEM 2.	Properties

ITEM 3.	Legal Proceedings

ITEM 4.	Mine Safety and Health Administration Safety Data

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ITEM 5.	Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

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ITEM 6.	Selected Financial Data

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(A)	Represents average net sales price including the effect of derivative transactions.

(B)	Represents proved developed and undeveloped gas reserves at period end.

(C)	Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 0.6 million tons, 0.5 million tons, 0.6 million tons, 0.2 million tons, and 0.3 million tons for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.

(D)	Represents proven and probable coal reserves at period end, excluding equity affiliates.

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ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations

•	Record total gas production of 172.4 Bcfe in 2013, 10% higher than 2012.

•	Record Marcellus Shale production of 57.8 Bcfe in 2013, 58% higher than 2012.

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Completed a lease with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for 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.  An up-front bonus payment of $46.3 million was paid at closing. Noble Energy, our joint venture partner, acquired 50% of the acres and accordingly, reimbursed CONSOL Energy for 50% of the associated costs. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. To date, less than 1% of this amount has been released from escrow. We must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and the bonus is foregone.

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Entered into a farm-in agreement for approximately 90 thousand additional Marcellus Shale acres in West Virginia.  Consideration of up to $190 million will be paid by CONSOL Energy in two installments:  (i) 50% was paid at closing and (ii) the balance due over time as the acres are drilled.  Closing occurred on December 5, 2013. Noble Energy, our Marcellus Shale joint venture partner, acquired a 50% interest in the acres and accordingly, will reimburse CONSOL Energy for 50% of the associated costs.

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Completed the sale of Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of CONSOL Energy's longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy).  The CCC mines sold were McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 26.7 million tons of thermal coal in 2013 and 28.8 million tons of thermal coal in 2012. Murray Energy acquired approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations were included in the transaction. CONSOL Energy received $850 million in cash as a result of the transaction. CONSOL Energy retained an overriding royalty interest in certain reserves sold in the transaction that included minimum royalty payments of $42 million. Additionally, Murray Energy acquired approximately $1.9 billion of other postretirement benefit plan liabilities, $100 million of workers compensation liabilities, $50 million of coal workers’ pneumoconiosis liabilities, $10 million of long term disability liabilities, $155 million of environmental liabilities and CONSOL Energy’s UMWA 1974 Pension Trust Obligations. The pre-tax financial gain resulting from the transaction was $1,035 million.

•	In conjunction with the sale of CCC and certain of its subsidiaries, CONSOL Energy realigned its dividend policy to reflect the company’s increased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, or a 2014 annual rate of $0.25 per share, beginning with the first quarter of 2014.

•	Our 2014 annual gas production is expected to be between 215 - 235 Bcfe with annual production growth of 30% for 2015 and 2016.

•	Our 2014 gas capital investment is expected to be $1,110 million.

•	Our 2014 coal production is expected to be between 30.1 - 32.1 million tons.

•	Our 2014 coal capital investment is expected to be $390 million.

•	Pension settlement accounting may occur in 2014 related to staff reduction that occured in relation to the sale of CCC and certain subsidiaries.

•	BMX Mine is expected to begin longwall mining during the first quarter of 2014.

•	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 pre-tax gain on the sale of assets.

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•	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 pre-tax 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 qualified and non-qualified salary retirement pension plans exceeding the annual projected service and interest costs of the plans. The pension settlement resulted in a $39.5 million pre-tax expense adjustment. Many of the lump sum payments in the year ended December 31, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive Plan.

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A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the year ended December 31, 2013. As a result of the Company's review of the title defects, asserted by its joint venture partner Noble Energy, and working in collaboration with Noble, CONSOL Energy has conceded defects on acreage with a value of $23.1 million. See Note 11- Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.

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In the year ended December 31, 2013, an agreement was reached for resolution of the class actions brought by shareholders of CNX Gas alleging that the price paid 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 was not fair. The total settlement provided for a payment to the plaintiffs of $42.7 million, of which the CONSOL Energy’s portion was $19.2 million. See Note 24 - Commitments and Contingencies, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.

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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 $34.3 million in the year ended December 31, 2013.

•	Severance and related costs of $9.5 million pre-tax expense related to the change in control of the 5 coal mines and the reduction of supporting administrative staff was reflected in the 2013 financial results.

•	Settlement and curtailment gains totaling $1.6 billion were recognized related to the company’s obligations under the Other Postretirement Benefits, Workers’ Compensation, Pension, Coal Workers’ Pneumoconiosis, and Long-Term Disability plans as a result of the sale to Murray Energy.

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•	Gathering costs increased in the period-to-period comparison due to a $0.04 per Mcfe increase in processing fees associated with natural gas liquids and a $0.10 per Mcfe increase in firm transportation costs.

•	Depreciation, depletion and amortization rates increased due to higher units-of-production for producing properties in the period to period comparison offset, in part, by additional volumes.

•	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.

•	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. The incident caused a total of four longwalls to be idled for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period, which resulted in lower direct operating costs per ton produced.

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•	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.

•	Depreciation, depletion and amortization was improved primarily due to the idling of operations at the Fola Mining Complex in August 2012. The improvements were offset, in part, by higher costs in the 2013 period related to Bailey, Enlow Fork, and Buchanan Mines running for the full year in 2013 compared to being idled at various times throughout 2012.

•	Average direct operating costs were impaired due to CONSOL Energy entering into a new longwall lease in 2013 at our Bailey Mine.

•	Costs were impaired in the current period due to the idling of the Buchanan Mine for various months throughout 2012. Although idled at times during 2012, the Buchanan Mine ran the continuous miners and worked on various projects which increased overall 2012 unit costs.

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

•	Employee wages and related expenses decreased $2 million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan, as previously discussed. There was also lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison related 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 $7 million in the period-to-period comparison. Various legal proceedings accounted for $3 million of the increase and an additional $2 million was related to tax advisory services. The remaining increase was due to various other corporate initiatives, none of which were individually significant.

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

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•	CONSOL Energy has 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 carrying value to CONSOL Energy of $23 million for the year ended December 31, 2013 compared to $4 million for the year ended December 31, 2012.

•	Dry hole costs increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Exploration expense increased $2 million due to increased exploratory expenses associated primarily with the Utica operating areas and various transactions that occurred throughout both periods, none of which were individually material.

•	Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The $4 million decrease is due to fewer lease expirations in the current period when compared with the prior period.

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•	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 $19 million increase is due to increased firm transportation capacity which has not been utilized by active operations.

•

Stock-based compensation was $6 million higher in the period-to-period comparison primarily due to additional non-cash expense and accelerated non-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to the prior year. 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.

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

•	The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense decreased $6 million due to lower projected payouts in the 2013 period.

•

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 wells drilled in the applicable period, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.

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

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

•	Project expense increased in the 2013 period due to a longwall overhaul and a waterline extension project at Bailey Mine.

•	Power expense increased in the 2013 period due to an increase in rates in the current year.

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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 incident caused a total of four longwalls to be idled for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period, which resulted in lower direct operating costs per ton produced.

•	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.

•	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, as 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, in part, 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, as discussed previously. The decrease in unit costs was also offset, in part, 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 year ended December 31, 2013 compared to $271 million in the year ended December 31, 2012. The decrease of $225 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in a gain on sale of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in a gain on sale of $112 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in a gain on sale of $25 million and the sale of 50% interest in a joint venture in Alberta, Canada that resulted in a gain on sale of $15 million. See Note 3—Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form

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•	In the year ended December 31, 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 $6 million decrease in other income is due to various items, none of which were individually material.

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The $72 million 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. The mine was idled during this period but there was continued advancement of the mine and on-going projects which resulted in $42 million of expense.

•

Closed and idle mine costs decreased approximately $27 million for the year ended December 31, 2013 compared to the year ended December 31, 2012.  Closed and idle mine costs decreased $16 million due to the decision to shutdown the Fola Mining Complex in August 2012 and $18 million due to the decision to idle operations at Buchanan Mine for three months in 2012. These decrease were offset, in part, by an increase of $8 million in costs incurred primarily by the Amonate Complex. Other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material resulted in an additional $1 million decrease.

•	Litigation Contingencies decreased $17 million in the year-to-year comparison due to various items. See Note 24- Commitments and Contingent Liabilities in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.

•

In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer received a severance payment equal to one year's salary. Approximately 100 employees volunteered for the program. Severance pay was approximately $13 million.

•	General and Administrative Expense decreased $2 million due to various items that occurred in both periods, none of which were individually material.

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

•

Stock-based compensation was $10 million higher in the period-to-period comparison primarily due to additional non-cash expense and accelerated non-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program.  The new program replaces several previously provided long-term executive compensation award programs.  The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.

•	Other expenses related to the coal segment decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Pennsylvania Turnpike Settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million.

•	Equity in Earnings increased $1 million due to an increase in earnings from our Equity Affiliates in the current period.

•	Towing income remained consistent in the period to period comparison.

•	Other income remained consistent in the period to period comparison.

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

•

The CNX 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 of 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 $43 million, of which the Company paid $19 million.

•

Corporate initiative fees and other legal charges reflect various charges for services related to corporate initiatives to evaluate 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 case. See Note 11 - Property, Plant and Equipment and Note 24 - Commitments and Contingent Liabilities of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Accelerated Bank Fees represents accelerated amortization of the previously deferred fees in relation to the capacity reduction in CONSOL Energy's revolving credit facility from $1.5 billion to $1.0 billion.

•	Bank fees increased $2 million mainly due to higher borrowings on the CNX Gas revolving credit facilities in the period-to-period comparison.

•	Interest Expense decreased $4 million primarily due to a reduction in capitalized interest due to lower capital expenditures for major construction projects in the current period.

•	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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•	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 the 2011 Antero transactions resulted in lower average costs per Mcfe 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 as compared with the prior year resulted in a lower units-of-production rate.

•	Lower direct administrative, selling and other costs per Mcfe 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.

•	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.

•	The idled longwall at Buchanan Mine during portions of 2012 resulted in an increase in unit costs as the fixed costs were allocated over fewer tons.

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

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

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

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Employee wages and related expenses decreased $9 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 of the salaried other post-employment benefit plan. See Note 16—Pension and Other Postretirement Benefit Plans and Note 17—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense increases

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

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

•	Contributions decreased $1 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 throughout both periods, none of which were individually material.

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•	Gain on sale of assets decreased $30 million due to gains on the Hess transaction and Antero overriding royalty interest of $53 million and $41 million respectively, both of which occurred in 2011. Additionally, CONSOL Energy incurred a $64 million loss on the Noble transaction during 2011.

•	Interest income increased $20 million due to the notes receivable which were part of the Noble joint venture transaction.

•	Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% owned affiliate. CONE was formed in relation to the Noble joint venture transaction.

•	The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.

•	Lease expiration costs increased $12 million primarily due to lease expirations where CONSOL Energy allowed primary lease terms to expire.

•	CONSOL Energy reviewed title defect notices, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage which had a carrying value to CONSOL Energy of $4 million for the year ended December 31, 2012.

•	Exploration expense increased $7 million due to higher exploratory expenses associated with the Utica operating area and various other transactions that occurred throughout both periods, none of which were individually material.

•	Dry Hole Costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	Legal fees were related to CNX Gas royalty litigation and title defect work, as previously discussed.

•

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 the 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.

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

•

The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period and an increased allocation of expense from CONSOL Energy as a result of exceeding corporate targets.

•	Stock-based compensation remained consistent in the period-to-period comparison. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.

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

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

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•	Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 20.3 million tons in 2012 compared to 21.9 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.

•	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 serviced in the current year.  Additional contractor

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•	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.

•	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 year-to-year 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 year-to-year comparison due to fewer tons being sold under contracts that require commissions.

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•	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.

•	Mine maintenance and supplies per ton produced decreased due to the mix of mines producing tons that were shipped as high volatile metallurgical coal. Mines with lower cost structures produced a larger portion of the high volatile metallurgical coal shipped in the current year compared to the prior year.

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

•	Improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.

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•	The Buchanan longwall was idled during the months of March, April and October of 2012 which resulted in higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the months when the longwall was idled. This negatively impacted unit costs.

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Low volatile metallurgical coal production was 3.7 million tons for the year ended December 31, 2012 compared to 5.7 million tons for the year ended December 31, 2011. Production was significantly lower in the year-to-year comparison due to the Buchanan Mine being idled for portions of 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Late in 2012, a five day work week instead of the normal seven

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Gain on sale of assets attributable to the Other Coal segment were $271 million for the year ended December 31, 2012 compared to $5 million for the year ended December 31, 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 Western Canada, Illinois and West Virginia that resulted in income of $112 million. See Note 3—

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For the year ended December 31, 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 December 31, 2011.

•	Gain on issuances of pipeline right-of-ways to third parties decreased $8 million in the year-to-year comparison, primarily due to a $10 million pipeline right-of-way to a third party issued in the year ended December 31, 2011.

•	The remaining $1 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.

•

Closed and idle mine costs increased approximately $61 million for the year ended December 31, 2012 compared to the year ended December 31, 2011.  The increase was the result of $30 million additional costs related to reclamation liabilities and on-going idling costs incurred at the Fola Complex for the year ended December 31, 2012.  Closed and idle mine costs increased $20 million as the result of a 2012 decision to temporarily idle Buchanan Mine in 2012.  Closed and idle mine costs increased $11 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.

•	Bailey Belt incident costs represents expenses related to continued advancement of the mines and on-going projects at the mines that took place during the idled phase when belt reconstruction was occurring.

•

In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer will receive a severance payment equal to one year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay was approximately $13 million and was recognized for the year ended December 31, 2012. This was paid in January 2013.

•	Litigation contingencies increased $5 million in the year-to-year comparison due to various items. See Note 24-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.

•	General and Administrative Expense related to the other coal segment decreased by $21 million primarily due to a reduction of wages and related expenses.

•	Purchased coal costs decreased approximately $22 million in the year-to-year comparison primarily due to differences in the quality of coal purchased, decreases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.

•

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 almost completely offset in freight revenue. The $68 million decrease in freight revenue was due to decreased shipments which CONSOL Energy contractually provides transportation services.

•	Other costs related to the coal segment increased $7 million due to various other transactions that occurred throughout both periods, none of which are individually material.

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•	Interest Expense decreased $24 million in the period-to-period comparison. Interest expense decreased due to an increase in capitalized interest related to higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $310 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 year ended December 31, 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 $5 million mainly due to lower borrowings on the revolving credit facilities in the period-to-period comparison and also due to the refinancing and extension of the credit facility on April 12, 2011.

•	Evaluation fees for non-core asset dispositions and other legal charges decreased $2 million in the period-to-period comparison due to various corporate initiatives.

•	Various other corporate expenses decreased $7 million due to various transactions that occurred throughout both periods, none of which were individually material.

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•	stock price on measurement date,

•	exercise price defined in the award,

•	expected dividend yield based on historical trend of dividend payouts,

•	risk-free interest rate based on a zero-coupon treasury bond rate,

•	expected term based on historical grant and exercise behavior, and

•	expected volatility based on historic and implied stock price volatility of CONSOL Energy stock and public peer group stock.

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•	geological conditions;

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

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

•	assumptions governing future prices; and

•	future operating costs.

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•	Net income increased $271 million in the period-to-period comparison;

•	Discontinued operations changes decreased $675 million primarily as a result of the gain on sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013;

•	Operating cash flows increased $214 million in the period-to-period comparison due to changes in the gain on the sale of assets. See Note 3 - Acquisitions and Dispositions in the Notes to Audited Financial Statements in Item 8 of this Form 10-K for more information; and

•	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 $251 million due to:

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Gas segment capital expenditures increased $441 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, additional gas drilling rights acquired from Dominion Transmission in West Virginia and various other individually insignificant projects;

•	Coal segment capital expenditures decreased $196 million. The decrease was comprised of a $27 million decrease in Bailey Mine Expansion projects. Longwall shield projects decreased $71 million as well as an additional $98 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material; and

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•	Other capital expenditures increased $6 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•	Proceeds from sale of assets decreased $161 million due to various items that occurred throughout both periods. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

•	Discontinued operations changes increased $1,106 million primarily as a result of the gain on the sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013.

•	Distributions from/investments in equity affiliates decreased $12 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•

Restricted cash increased $116 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. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

•	In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy received $16 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. Total dividends paid in the year ended December 31, 2013 were $86 million as compared to $142 million in dividends paid in the period ended December 31, 2012.

•	In 2013, CONSOL Energy repaid $38 million of borrowings under its Securitization Facility. In 2012, CONSOL Energy had proceeds of $38 million from the 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 excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2014 contributions are expected to approximate $25 million to $35 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.

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•	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. Payment of the principal and interest on the notes are guaranteed by CONSOL Energy.

•	Advance royalty commitments of $11 million with an average interest rate of 7.93% per annum.

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

•	An aggregate principal amount of $56 million of capital leases with a weighted average interest rate of 6.19% per annum.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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(a)	This category includes investments in US common stocks and corporate debt.

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(b)

This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c)

This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.

(d)

This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(e)

This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.

(f)

This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

(g)

This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h)

This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI Emerging Markets Index.

(i)	This category invests in companies operating in developed markets, globally. The strategy targets a diversified portfolio of equity securities issued by companies which the investment managers believe will exhibit less volatility in their price performance relative to the broad equity market as described by the MSCI World Index. The strategy is benchmarked to the MSCI World Index.

(j)

This category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.

(k)

This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

(l)	This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.

(m)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.

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(n)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.

(o)

This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.

(p)

This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through active management while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Corporate Index and 10% to the Barclay’s Capital Long Treasury.

(q)	This category invests primarily in long dated US Treasury STRIPS often with maturities greater than 20 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital U.S. 20+ Year STRIPS Index.

(r)	This category invests primarily in fixed income securities from issuers either located in developing/emerging markets or those rated below investment grade (high yield), globally, The strategy is benchmarked to a blended index of 50% JP Morgan Government Bond Index Emerging Markets Global Diversified and 50% Bank of America/Merrill Lynch Global High Yield Index.

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(A)	Included in the Coal segment are sales of $495,242 to Xcoal Energy & Resources and $346,424 to Duke Energy each comprising over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $17,346, $14,684 and $1,102 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $20,512, $206,060 and $65,103 for Coal, Gas and All Other, respectively.

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(D)	Included in the Coal segment are sales of $382,843 to Xcoal Energy & Resources comprising over 10% of sales.

(E)	Includes equity in earnings of unconsolidated affiliates of $17,318, $9,562 and $168 for Coal, Gas and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $19,517, $143,876 and $59,437 for Coal, Gas and All Other, respectively.

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(*)	Includes costs incurred whether capitalized or expensed.

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(1)	Net acres include acreage attributable to our working interests of the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

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(a)	Revisions are primarily due corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes were partially offset by upward revisions attributable to efficiencies in operations and well performance and had the total affect of a negative revision for 2011.

(b)	Revisions are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance and had the total affect of the positive revisions for 2013 and 2012.

(c)	Extensions and Discoveries are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.

(d)

Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

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(a)	During 2013, various exploration and development drilling and evaluations were completed. Approximately, $202,066 of capital was spent in the year ended December 31, 2013 related to undeveloped reserves that were transferred to developed.

(c)

Extensions and discoveries include approximately 683 Bcfe which were initially classified as unproved related to the DTI and Airport lease acquisitions.  These reserves were subsequently reclassified to proved undeveloped reserves utilizing reliable technologies which include wire line open hole log data, performance data, log cross sections, core data, and statistical analysis.  The statistical method utilized production performance from Consol Energy's and competitors' wells.  Geophysical data include data from Consol's wells, published documents, state data-sites and were used to confirm continuity of the formation.

(d)

Included in proved undeveloped reserves at December 31, 2013 are approximately 226,063 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

ITEM 9A.	CONTROLS AND PROCEDURES

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ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBIT INDEX

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