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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;

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

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

•	exposure to multi-employer pension plan liabilities;

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

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

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

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

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

•	risks associated with our debt;

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

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

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

•	other factors discussed in this 2012 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

•	Safety,

•	Compliance, and

•	Continuous Improvement.

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•	We produce one of the largest amounts of coal east of the Mississippi River;

•	We control one of the largest amounts of recoverable coal reserves east of the Mississippi River;

•	We control the fourth largest amount of recoverable coal reserves among United States coal producers; and

•	We are one of the largest United States producers of coal from underground mines.

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•	We are one of the largest natural gas producers in Appalachia with approximately 15,000 total gross wells in Appalachia comprising 8% of all Appalachian wells based on 2011 U.S. Energy Information Administration data, the latest year for which statistics are available.

•	We are one of the largest CBM producers, with production equal to approximately 40% of total Appalachian CBM production and 75% of Northern Appalachian production (excluding Alabama) based on 2011 U.S. Energy Information Administration data, the latest year for which statistics are available.

•	We gather essentially all of our own production independently or through company operated joint ventures, and we operate one of the largest gas gathering networks in Appalachia. We also own or operate over 4,500 miles of gathering pipelines.

•	We have been a pioneer in the exploration of unconventional gas including coalbed methane, Marcellus, Utica, Chattanooga, Huron and New Albany Shales.

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

•	environmental and government regulation;

•	coal quality;

•	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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(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, 2012. 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 11 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. Also, excluded from the table above are approximately 209.3 million tons of reserves at December 31, 2012 that are assigned to projects that have not produced coal in 2012. These assigned reserves are in the Northern Appalachia (northern West Virginia and Pennsylvania), Central Appalachia (Virginia and eastern Kentucky), the Western U.S. (Utah) and Illinois Basin (Illinois) regions. These reserves are approximately 64% owned and 36% leased.

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(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, and the Western U.S. 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; or

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

•	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.

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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 acre 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 acre 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 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.

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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.

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

b.

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

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

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

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

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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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•	the Surface Mining Control and Reclamation Act of 1977,

•	the Clean Air Act,

•	the Clean Water Act,

•	the Endangered Species Act,

•	the Resource Conservation and Recovery Act,

•	the Comprehensive Environmental Response, Compensation and Liability Act,

•	the Toxic Substances Control Act, and

•	the Emergency Planning and Community Right to Know Act,

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ITEM 1A.	Risk Factors

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•	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 high volatile steam coal as higher-priced 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 coal or gas reserves; and

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

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

•

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 27% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 46% in 2011 to 37.5% 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.

•	the domestic supply of natural gas;

•	the consumption pattern of industrial consumers, electricity generators and residential users and 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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•	variations in thickness of the layer, or seam, of coal;

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

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	weather conditions; and

•	security breaches or terroristic acts.

•	unexpected drilling conditions;

•	title problems;

•	pressure or irregularities in geologic formations;

•	equipment failures or repairs;

•	fires, explosions or other accidents;

•	adverse weather conditions;

•	reductions in natural gas prices;

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•	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.

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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, including the cost of materials.

•	geological conditions;

•	changes in governmental regulations and taxation;

•	the amount and timing of actual production;

•	assumptions governing future prices;

•	future operating costs; and

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•	capital costs of drilling new wells.

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•	postretirement medical and life insurance ($3.0 billion);

•	coal workers' black lung benefits ($184.1 million);

•	salaried retirement benefits ($224.9 million); and

•	workers' compensation ($179.6 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;

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•	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.

•

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

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

•

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

•

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.

•	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

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

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Under our joint venture agreements with Noble Energy and Hess, each of them has the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. CONSOL Energy then can review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party can submit the defect to an arbitrator for resolution. CONSOL Energy also has the right to require the defected acreage to be reassigned in certain circumstances. We are currently engaged in this title review process with Noble and Hess. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's and Hess's respective aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase. To date, Noble has asserted formal title defects with respect to approximately 30,171 gross deal acres, which have an aggregate transaction value of $196 million. We believe that we will resolve most of those defects favorably to CONSOL Energy. To date, we have conceded defects to Noble which have an aggregate value equal to less than the applicable deductibles and the impact of these conceded defects on the Company's financial statements has not been material. In the case of our Ohio Utica Shale joint venture with Hess, based on title work performed by Hess, we believe that there are chain of title issues with respect to approximately 36,000 of the joint venture acres, most of which likely cannot be cured.  Hess's 50% interest in these 36,000 acres has an allocated transaction value of approximately $146 million and may result in a corresponding reduction of the associated carried interest. The loss of these Utica Shale acres itself will not have a material impact on the Company's financial statements. After accounting for these defective acres, there are approximately 161,000 acres in our Ohio Utica Shale joint venture with Hess.

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

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•	limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our coal and gas 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.

•	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

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)	See Note 24–Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for sales and freight by operating segment.

(B)

Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding for purposes of computing dilutive earnings per share are due to the inclusion of the weighted average dilutive effect of employee and non-employee share-based compensation granted, totaling 1,548,243 shares, 2,323,230 shares, 2,117,243 shares, 2,127,893 shares, and 2,293,581 shares for the year ended December 31, 2012, 2011, 2010, 2009, and 2008, respectively.

(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: 0.5 million tons, 0.6 million tons, 0.3 million tons, 0.3 million tons, and 1.7 million tons for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively.

(D)	Represents proven and probable coal reserves at period end.

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

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

(G)

Net cash used in investing activities includes $327,964 for collection of Noble Note Receivable related to the 2011 agreement, $169,500 related to the disposition of the Northern Powder River Basin assets, $51,869 related to the disposition of the Ram River & Scurry Ram assets, $26,000 related to the disposition of the Elk Creek property, and $13,023 related to the disposition of the Burning Star No. 4 property in the year ended December 31, 2012. The year ended December 31, 2011 includes $485,464 related to the Noble transaction, $190,381 related to the Antero Transaction, and $54,099 related to the Hess Transaction. The year ended December 31, 2010 includes $3,470,212 and $991,034 related to the Dominion Acquisition and the purchase of CNX Gas Non-Controlling Interest, respectively.

(H)

Adjusted EBIT is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, loss on debt extinguishment, and abandonment of long-lived assets. Adjusted EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although adjusted EBIT and adjusted EBITDA are not measures of performance calculated in accordance with generally accepted accounting principles, management believes that they are useful to an investor in evaluating CONSOL Energy because they are widely used in the coal industry as measures to evaluate a company's operating performance before debt expense and cash flow. Financial covenants in our credit facility include ratios based on adjusted EBITDA. Adjusted EBIT and adjusted EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because adjusted EBIT and adjusted EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management's discretionary use of funds depicted by adjusted EBIT and adjusted EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconcilement of adjusted EBIT and adjusted EBITDA to financial net income is as follows:

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(I)	For purposes of computing the ratio of earnings to fixed charges, earnings represent income before income taxes plus fixed charges. Fixed charges include (a) interest on indebtedness (whether expensed or capitalized), (b) amortization of debt discounts and premiums and capitalized expenses related to indebtedness and (c) the portion of rent expense we believe to be representative of interest.

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

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•	In April 2012, CONSOL Energy sold its non-producing Elk Creek reserves in southern West Virginia. The transaction resulted in cash proceeds of $26 million and a gain on sale of assets of $11 million.

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

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

•	In June 2012, CONSOL Energy expanded an existing mining joint venture with a privately-held company in Central Pennsylvania. The joint venture will self-fund, through retained earnings, a $54 million (gross) expansion in 2012 and 2013. The expansion will enable CONSOL Energy's share of high-vol and mid-vol forecasted coal production to increase from 150,000 tons in 2012 to 900,000 tons in 2015.

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In December 2012, CONSOL Energy sold non-producing western Canadian coal assets for $103 million. Ram River Coal Corp., a private Ontario company created by Forbes & Manhattan Inc. (F&M) (a private merchant bank headquartered in Toronto, Canada) acquired 100% of CONSOL Energy's Ram River and Scurry Ram coal properties for aggregate consideration of $105 million ($102.5 million payable to CONSOL Energy). On closing, Ram River Coal Corp. made an aggregate cash payment of $55.0 million ($52.5 million payable to CONSOL Energy) and under the terms of the asset purchase agreement provides for additional payments to CONSOL Energy of $25.5 million on or before June 21, 2013 and $24.5 million on or before June 21, 2014. The transaction resulted in an after-tax gain of $60.7 million.

•	In December 2012, CONSOL Energy agreed to sell its interest in other coal assets, subject to certain conditions, in Alberta, for $24 million. The buyer is Riversdale Resources, headquartered in Sydney, Australia. The primary asset is Grassy Mountain Surface Mine. The sale is anticipated to close during the second quarter of 2013, and as such, no gain has been recognized as of December 31, 2012.

•	CONSOL Energy continues to explore potential sales of assets.

•

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 $13.3 million and was recognized in other accrued liabilities at December 31, 2012. These enhanced benefits were paid in January 2013.

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On July 27, 2012 a structural failure occurred at CONSOL Energy's newly installed above-ground conveyor system at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from the Bailey and Enlow Fork mines to the Bailey Preparation Plant. This incident caused a total of four longwalls to be idled for approximately three weeks, at which point one rebuilt conveyor belt was re-started. Production from these mines was at approximately 60% of normal for most of the remainder of the third quarter. The company's net income would have been an estimated $53 million higher, had the conveyor belt incident not occurred. This impact is before the receipt of any insurance proceeds and any other proceeds under the indemnity provisions of the construction contract. CONSOL Energy has received $2.3 million of business interruption insurance proceeds related to this incident, included in its 2012 results of operations. Although CONSOL Energy's insurance claim is higher than the proceeds received to date, there is no guarantee that additional monies will be received.

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In June 2012, CONSOL Energy announced that it acquired a non-controlling interest in Epiphany Solar Water Systems, a privately-held company founded in New Castle, PA in 2009. Epiphany Solar Water Systems is testing what is believed to be the world's first concentrated solar powered water purification system. Under the agreement, CONSOL Energy has made an initial investment of $0.5 million and one of its Marcellus gas well locations in Greene County served as the site to pilot test this solar powered water purification system. Initial testing of the Epiphany unit demonstrated the efficacy of the approach. Based on results of the pilot test, system improvements and upgrades are being implemented. Additional testing is ongoing and will be used to evaluate system enhancements in the coming months.

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In April 2012, CONSOL Energy announced certain changes to the salaried other post-retirement benefit plan that current retirees and current active employees will receive as of January 1, 2014. The change provides a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B and Part D premiums and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug coverage. Employees who work or worked in corporate or operations support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefit. CONSOL Energy remeasured the salaried other postretirement plan as of March 31, 2012 to recognize these changes. The remeasurement reflects the reduction in benefits and the change in discount rate from 4.51% at December 31, 2011 to 4.57% at March 31, 2012. The remeasurement resulted in a reduction of approximately $80.6 million of Other Post-Retirement Benefits (OPEB) liability with a corresponding offset to Other Comprehensive Income, net of applicable deferred taxes. The change resulted in a $9.4 million reduction in OPEB expense compared to what was originally expected to be recognized for the year ended December 31, 2012. The change was made to align CONSOL Energy's corporate and operational support compensation package more closely with our peer group.

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

•	On December 10, 2012, CONSOL Energy's board of directors accelerated the declaration and payment of the regular quarterly dividend of $0.125 per share, payable on December 28, 2012, to shareholders of record on December 21, 2012.

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Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations (although prices for some of these commodities declined during the year from previous years), (ii) increased scrutiny of existing safety regulations and the development of new safety regulations and (iii) additional environmental restrictions.

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Federal and state environmental regulators are reviewing our operations more closely and are more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of chlorides in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million.  The new facility must be placed into service no later than May 2013.

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Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business.   These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules.  All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal.  Other examples are the Mercury and Air Toxic Standards (MATS) (remanded by the court and reproposed 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.  Although the EPA intends to reconsider certain aspects of these new rules, some older coal fired

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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 will apply to new power plants and to existing plants that make major modifications. If the rules are adopted as proposed, the only new coal fired power plants that will be able to meet the proposed emission limits will be coal fired plants with carbon dioxide capture and storage (CCS). Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal fired electric generation units uneconomical compared to new gas fired electric generation units. Thus, if finalized the proposed rules could seriously threaten the construction of new coal fired electric generating units.

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

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

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Under our joint venture agreements with Noble Energy and Hess, each of them has the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's and Hess's respective aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase.  To date, Noble has asserted formal title defects with respect to approximately 30,171 gross deal acres, which have an aggregate transaction value of $196 million. We believe that we will resolve most of those defects favorably to CONSOL Energy. To date, we have conceded defects to Noble which have an aggregate value equal to less than the applicable deductibles and the impact of these conceded defects on the Company's financial statements has not been material. In the case of our Ohio Utica Shale joint venture with Hess, based on title work performed by Hess, we believe that there are chain of title issues with respect to approximately 36,000 of the joint venture acres, most of which likely cannot be cured. Hess's 50% interest in these 36,000 acres has an allocated transaction value of approximately $146 million and may result in a corresponding reduction of the associated carried interest. The loss of these Utica Shale acres itself will not have a material impact on the Company's financial statements. After accounting for these defective acres, there are approximately 161,000 acres in our Ohio Utica Shale joint venture with Hess.

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A pension settlement charge is reasonably possible to occur in 2013. When lump sum payments from the pension plan exceed the service and interest expense, pension settlement accounting requires unamortized actuarial gains and loss related to the lump sum payouts be amortized immediately. The 2013 threshold for pension settlement recognition is $55 million. If the threshold for pension settlement is reached, the pension settlement charge could be material to the financial results of CONSOL Energy. Also, pension settlement would require the pension plan to be remeasured using updated assumptions. The updated assumptions would include resetting the discount rate used in the actuarial calculation.

•	CONSOL is also in negotiations with the authority that operates the Pittsburgh International Airport for the lease of the oil and gas rights on approximately 8,800 acres surrounding the airport. These are contiguous acres which are in the liquids area of the Marcellus Shale play.

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

•	The idle longwalls at the Blacksville Mine and the Buchanan Mine during March and April 2012 resulted in an increase in unit costs of approximately $2.16 per ton 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 labor and labor related expenses increased primarily as result of the impact of the UMWA contract wage increases, offset, in part, by lower overtime hours worked.

•	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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•	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 thousand cubic feet sold. Fixed costs are allocated over increased volumes, resulting in lower unit costs.

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

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

•	Employee wages and related expenses decreased $8 million primarily attributable to lower salary OPEB expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions, and a modification to the benefit plan for certain salaried employees.

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•	Consulting and professional services decreased $5 million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising and promotion campaign.

•	Contributions increased $1 million in the period-to-period comparison due to various transactions, none of which were individually material.

•	Miscellaneous general and administrative expenses decreased $4 million in the period-to-period comparison due to various transactions throughout both periods, none of which were individually material.

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•	Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 48.8 million tons in 2012 compared to 51.7 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.

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

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

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

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

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

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•	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.

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

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•	The Buchanan longwall was idled during the months of March and April which resulted in $18.53 per ton higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the month when the longwall was idled. This negatively impacted unit costs.

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Low volatile metallurgical coal production was 3.7 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 in early September 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Production resumed in early November 2012 with a five day work week instead of the normal seven day work week. Fixed costs were then spread over fewer tons produced which increased all costs on a per unit basis. Buchanan Mine was also idled in March and April 2012 which impacted production.

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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 2—Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail of these sales. The remaining $3 million change was related to various transactions that occurred throughout both periods, none of which were individually material.

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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 $9 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.

•	Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.

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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The $89 million decrease in freight revenue was due to decreased shipments which CONSOL Energy contractually provides transportation services.

•	Purchased coal costs decreased approximately $24 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.

•	General and Administrative Expense related to the other coal segment decreased by $7 million primarily due to a reduction of wages and related expenses.

•	Litigation contingencies increased $10 million in the year-to-year comparison due to various items. See Note 23-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.

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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.

•	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.

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Closed and idle mine costs increased approximately $46 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 decreased $4 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.

•	Other costs related to the coal segment decreased $2 million due to various other transactions that occurred throughout both periods, none of which are 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. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

•	Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% affiliate. CONE was formed in relation to the Noble joint venture transaction. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

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

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Lease Expiration costs increased $12 million primarily due to lease expirations relating to locations where CONSOL Energy allowed primary lease terms to expire. Additionally, the increase also relates to various title defect issues identified as part of the Noble transaction. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this form 10-K for additional information.

•	Exploration expenses increased $11 million due to increased exploratory expenses associated with the Utica operating area and various other transaction 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.

•	Legal fees were related to CNX Gas royalty litigation and title defect work. See Note 23 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this form 10-K for additional information.

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

•	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.

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The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety compliance, 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 the 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.

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

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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 remained constant in the period-to-period comparison.

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•	Average operating supplies and maintenance costs per ton sold were higher due to increased equipment overhauls, additional roof control and additional equipment maintenance.

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

•	Labor and labor related charges increased as a result of additional employees, increased overtime hours worked and the impact of the $1.50 per hour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related to the July 2011 UMWA contract.

•	Average retirement and disability costs per ton increased primarily due to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs.

•	Royalties and production taxes increased due to a higher average sales price per ton sold.

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

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

•	Consulting and professional services increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.

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

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•	Average operating supplies and maintenance costs per thermal ton produced increased due to additional maintenance and equipment overhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof

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Labor and related benefits were impaired on a cost per thermal ton sold basis due to higher costs and lower volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement and are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Non-represented benefit rates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover the benefits.

•	Average operating costs per thermal ton sold increased due to lower tons sold resulting in fixed costs being allocated over less tons resulting in higher unit costs.

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

•	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.

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

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•	Average operating costs per high volatile metallurgical ton produced increased due to the mix of mines selling coal on the high volatile metallurgical coal market. As higher cost structure mines sell coal in the high volatile metallurgical

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

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

•	Average coal preparation costs per high volatile metallurgical ton produced increased due to additional maintenance projects that have been completed at our preparation plants in the period-to-period comparison.

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

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Average operating supplies and maintenance costs per low volatile metallurgical ton produced increased due to additional roof control costs, additional ventilation costs of coalbed methane gas, additional equipment overhaul costs and increased rock dusting. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of supports put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also

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•	These increases in costs were partially offset by a decrease in the power costs per low volatile metallurgical ton produced which were improved due to utility rate reductions that became effective in the 2011 period.

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•	Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.

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Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The increase was primarily due to the 3.6 million ton increase in export tons in the period-to-period comparison.

•	Purchased coal costs increased approximately $31 million in the period-to-period comparison primarily due to differences in the quality of coal purchased, increases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.

•	General and Administrative Expense related to the other coal segment increased by $15 million primarily due to an increase of wages and related expenses and professional services.

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Litigation expense of $25 million was recognized in the year ended December 31, 2010 related to a legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized in the year ended December 31, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million. Litigation expense related to various other potential legal settlements decreased $12 million in the period-to-period comparison. None of these items were individually material.

•	General and Administrative Expense related to the other coal segment increased by $15 million primarily due to an increase of wages and related expenses.

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Closed and idle mine costs decreased approximately $115 million in the year ended December 31, 2011 compared to the year ended December 31, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and the resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia increased $82 million. Also in the 2010 period, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $9 million as a result of the decision to permanently abandon Mine 84. Closed and idle mine costs for the 2010 period also included $6 million related to various asset abandonments that occurred, none of which were individually material. In addition, $9 million of reduced expenses were recognized in closed and idle mine costs for various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which

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•	Other costs related to the coal segment increased $6 million due to various other transactions that occurred throughout both periods, none of which are individually material.

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

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

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

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

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The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2011 period, increased number of employees, and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.

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

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

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

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•	Interest expense increased $41 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition in April 2010.

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

•	Evaluation fees for non-core asset dispositions increased $4 million in the period-to-period comparison due to various corporate initiatives that began in the 2010 period.

•	Bank fees increased $2 million in the period-to-period comparison due to the refinancing and extension of the previous $1.0 billion credit facility to $1.5 billion on April 12, 2011.

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Transaction and financing fees of $15 million were 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 CONSOL Energy's oil and gas properties. Transaction and financing fees of $61 million were incurred in the year ended December 31, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion.

•	Various other corporate expenses were $19 million in the year ended December 31, 2011 compared to $20 million in the year ended December 31, 2010. The decrease of $1 million was 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 decreased $244 million in the period-to-period comparison; and

•	The remaining $556 million decrease in operating cash flows was due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred through both years, none of which were individually material.

•	Capital expenditures increased $193 million due to:

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Coal segment increased capital expenditures $310 million in the period-to-period comparison. The increase was comprised of an additional $169 million in longwall shield projects, an additional $70 million for the Northern West Virginia RO system, an additional $37 million for an overland conveyor, an additional $30 million for the ongoing development of the BMX Mine (scheduled to begin production in early 2014) and an additional $34 million in various other individually insignificant projects, offset, in part, by a decrease of $30 million for a longwall face extension;

•	Gas segment capital expenditures decreased $134 million due to management's decision to decrease CBM and conventional drilling during 2012 in response to low gas prices;

•	Mineral lease expenditures associated with our advance mining royalties and leased coal assets increased $7 million in 2012; and

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•	Other capital expenditures increased $10 million related to various miscellaneous items, none of which were individually material.

•	Proceeds from sale of assets decreased $101 million due to:

•	Proceeds of an additional $158 million received in 2011 related to the Noble transaction;

•	Proceeds of $190 million received in 2011 related to the sale of the Antero overriding royalty interest;

•	Proceeds of $170 million received in 2012 related to the sale of non-producing Northern Powder River Basin (PRB) assets;

•	Proceeds of $52 million received in 2012 from the Ram River & Scurry Canadian asset sale;

•	Proceeds increased $25 million due to various other transactions that occurred throughout both periods, none of which were individually material.

•	Distributions from/investments in equity affiliates decreased $79 million due to:

•	Contributions of $42 million to CONE in order to meet the operating and capital expenditure;

•	A cash distribution of $67 million from CONE Gathering LLC; and

•	Net contributions of $30 million from various equity affiliates, none of which were individually significant.

•	Restricted cash receipts of $48 million associated with the Ram River & Scurry Canadian asset sale.

•	A make-whole provision of $266 million in 2011 to redeem 7.875% notes due in March 2012;

•	Payments of $284 million in 2011 on short term borrowing under the revolving credit facility;

•	Proceeds of $250 million in 2011 from the issuance of 6.375% senior unsecured notes due in March 2021;

•	Payments of $200 million in 2011 under the accounts receivable securitization program;

•	Proceeds of $25 million in 2012 from an interim funding agreement for the Bailey longwall shields;

•	Proceeds of $38 million in 2012 from the accounts receivable securitization program;

•	Increased dividend payments of $46 million in 2012 due to an additional dividend payment in 2012 associated with the acceleration of the fourth quarter dividend and the increase of the quarterly dividend for the entire year; and

•	An increase of $7 million due to various transactions throughout both period, none of which were individually material.

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(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2013 contributions are expected to approximate $50 million to $75 million.

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

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

•	An aggregate principal amount of $1.50 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 $6 million on other various rate notes maturing through June 2031.

•	An aggregate principal amount of $59 million of capital leases with a weighted average interest rate of 6.38% 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.

(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

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(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 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.

(j)

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.

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

(l)	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.

(m)	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.

(n)

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.

(o)	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

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(A)	Included in the Coal segment are sales of $546,982 to First Energy and $465,886 to Xcoal Energy & Resources each comprising over 10% of sales.

(B)	Includes equity in earnings of unconsolidated affiliates of $7,355, $9,562 and $10,131 for Coal, Gas and All Other, respectively.

(C)	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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(D)	Included in the Coal segment are sales of $662,109 to Xcoal Energy & Resources comprising over 10% of sales.

(E)	Includes equity in earnings of unconsolidated affiliates of $15,803, $4,231 and $4,629 for Coal, Gas and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $34,316, $96,914 and $50,806 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.

(a)	Plan and other revisions are due to corporate planning changes that affect the number of wells forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of a positive revision.

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

(c)	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,

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(a)	Gas equivalent reserves are expressed in billions of cubic feet equivalent (BCFE), determined using the ratio of six billion cubic feet of gas to one million barrels of oil.

(a)	During 2012, various exploration and development drilling and evaluations were completed. Approximately, $51,206 of capital was spent in the year ended December 31, 2012 related to undeveloped reserves that were transferred to developed.

(c)

Included in proved undeveloped reserves at December 31, 2012 are approximately 133,917 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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(a)	Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields. There were no wells removed from the previous year-end schedule.

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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 AND 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

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ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBIT INDEX

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