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•	deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;

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

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

•	our reliance on major customers;

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

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

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

•	our inability to maintain satisfactory labor relations;

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

•	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;

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

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

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

•	the impacts of various asbestos litigation claims;

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

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

•	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 and actions taken by the other party in our gas joint ventures may impact our financial position;

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

•	risks associated with our debt;

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

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

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

ITEM 1.	Business

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•	Safety

•	Compliance

•	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 2009 U.S. Energy Information Administration data, the latest year for which statistics are available.

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•	We are one of the largest CBM producers, with production equal to approximately 35% of total Appalachian CBM production and 59% of Northern Appalachian production (excluding Alabama) based on 2009 U.S. Energy Information Administration data, the latest year for which statistics are available.

•	We operate one of the largest gas gathering networks in Appalachia since we gather essentially all of our own production. We own and operate over 4,000 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; and

•	the reliability of fuel supply.

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(1)

The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2011. The heat value shown for accessible reserves is based on the same mining and processing methods as for the assigned reserves with adjustments made based on the variability found in exploration drill core samples. The heat values given have been adjusted to include moisture that may be added during mining or processing and 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 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)	Harrison Resources and Western Allegheny-Knob Creek are both equity affiliates in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy's 49% proportionate interest in Harrison Resources' and Western Allegheny-Knob Creek's reserves.

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

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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, Western U.S. and Western Canada 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.

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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.

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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.

(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.

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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.

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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 will not participate in the 1974 Pension Plan, but will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of credited service under the 1974 Pension Plan will 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 will have the right to elect to opt-out of future participation in the 1974 Pension Plan and upon such election, will receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014 - 2016) to the CDSP.

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

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, 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

•	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

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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;

•	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.

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•	geological conditions;

•	changes in governmental regulations and taxation;

•	the amount and timing of actual production;

•	assumptions governing future prices;

•	future operating costs; and

•	capital costs of drilling new wells.

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•	postretirement medical and life insurance ($3.2 billion);

•	coal workers' black lung benefits ($183.6 million);

•	salaried retirement benefits ($274.8 million); and

•	workers' compensation ($174.1 million).

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

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

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

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

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

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

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

•

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;

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•

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

•

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

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

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

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

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•	our production is less than expected;

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

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

ITEM 1B.	Unresolved Staff Comments

ITEM 2.	Properties

ITEM 3.	Legal Proceedings

ITEM 4.	Mine Safety and Health Administration Safety Data

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

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ITEM 6.	Selected Financial Data

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(A)	See Note 25–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 2,323,230 shares, 2,117,243 shares, 2,127,893 shares, 2,293,581 shares, and 2,099,124 shares for the year ended December 31, 2011, 2010, 2009, 2008, and 2007, 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: 0.6 million tons, 0.3 million tons, 0.3 million tons, 1.7 million tons and 0.5 million tons for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively.

(D)

Amounts include intersegment transactions. For entities that are not wholly owned but in which CONSOL Energy owns an equity interest, includes a percentage of their net production, sales and reserves equal to CONSOL Energy's percentage equity ownership. For coal, the proportionate share of recoverable reserves for equity affiliates was 145, 172, 170, 171 and 179 tons at December 31, 2011, 2010, 2009, 2008 and 2007 respectively. Sales of coal produced by equity affiliates were 0.5 million tons, 0.6 million tons, 0.4 million tons, 0.2 million tons and 0.1 million tons for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively. For gas, amounts include 100% of CNX Gas' basis for all years presented; they exclude the noncontrolling interest reduction. There was no equity in affiliates at December 31, 2011, 2010, 2009 and 2008. The proportionate share of proved gas reserves for equity affiliates was 3.6 Bcfe at December 31, 2007. Sales of gas produced by equity affiliates were 0.32 Bcfe for the year ended December 31, 2007.

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

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

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

(H)

Net cash used in investing activities includes $485,464 related to the Noble transaction, $190,381 related to the Antero Transaction, and $54,099 related to the Hess Transaction in the year ended December 31, 2011. 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. The year ended December 31, 2007 includes $296,724 related to the acquisition of AMVEST.

(I)

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. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and 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 EBITDA. EBIT and 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 EBIT and 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 EBIT and 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 EBIT and EBITDA to financial net income is as follows:

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(J)	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.

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

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

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On October 21, 2011, CNX Gas Company LLC (CNX Gas Company) completed a sale to a subsidiary of Hess Corporation (Hess) of 50% of its nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54 million, which is net of $5 million of transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to pay approximately $534 million in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gain on the transaction was $53 million and was recognized in the Consolidated Statements of Income as Other Income.

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On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certain Marcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company's undivided interest in certain of its existing Marcellus Shale wells and related leases. Cash proceeds of $485 million were received related to this transaction, which are net of $35 million transaction fees. Additionally, a note receivable has been recognized related to the two additional cash payments to be received on the first and a second anniversary of the transaction closing date. The discounted notes receivable of $312 million and $296 million have been recorded in Accounts and Notes Receivables-Notes Receivable and Other Assets-Notes Receivable, respectively. Subsequent to the transaction, an additional receivable of $17 million and a payable of approximately $980 thousand were recorded for closing adjustments and have been included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. The net loss on the transaction was $64 million and was recognized in the Consolidated Statements of Income as Other Income. As part of the transaction, CNX Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2.1 billion with certain restrictions. These restrictions include the suspension of carry if average natural gas Henry Hub prices are below $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry will remain suspended until average natural gas prices are above $4.00/MMBtu for three consecutive months. Restrictions also include a $400 million annual maximum on Noble's carried cost obligation.

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On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate each company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equity method of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $120 million and Noble contributed cash of approximately $68 million. CONE made a cash distribution to CNX Gas in the amount of $68 million. The cash proceeds have been recorded as cash inflows of $60 million and $8 million in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, on the Consolidated Statements of Cash Flow. The gain on the transaction was $7 million and was recognized in the Consolidated Statements of Income as Other Income.

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On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193 million. The net gain of $41 million is included in Other Income in the Consolidated Statements of Income.

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CONSOL Energy incurred costs of approximately $15 million in the year ended December 31, 2011 related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. The consents allowed an amendment to the indentures for each of those notes, clarifying that the transactions such as those contemplated by the August 2011 Asset Acquisition Agreements with Noble and Hess were permissible under those indentures.

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

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

b.

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

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

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, eligibility for various vacation days and sick days.

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In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle status since March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided it was in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The Company redeployed all of the movable equipment from the mine that could be used at other locations. The abandonment of this underground facility resulted in a $116 million charge to pre-tax earnings. See Note 10—Property, Plant and Equipment in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional disclosure. The Company expects the closure of Mine 84 to result in pre-tax cash savings of $18 million per year.

•	In April 2011, CNX Gas entered into an amendment to its senior secured credit agreement which increases the

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

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

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

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Federal and state environmental regulators are reviewing our operations more closely and 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 U.S. Environmental Protection Agency and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million.

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Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Further, other regulations would make it more expensive for our customers to operate their businesses, possibly inducing them to move to alternative fuel sources. For example, the EPA has issued a proposed rule that would regulate coal combustion residuals from coal fired electric generating facilities under the federal Resource Conservation and Recovery Act (RCRA) as either a hazardous waste under Subtitle C of RCRA or as a non-hazardous waste under Subtitle D of RCRA. If final rules are adopted consistent with either of the proposed alternatives, the cost of handling and disposal of coal combustion residuals could increase making it more expensive to generate electricity from coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by the EPA on July 6, 2011, although the effective date of the rule has been stayed by a court. CSAPR replaces the Clean Air Interstate Rule and regulates the amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Another example is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011. The new regulations, which will be published in February 2012, 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. Some older coal fired power plants may be retired or have operation time reduced rather than install additional expensive emission controls which could reduce the amount of coal consumed.

•	On April 19, 2011, the Pennsylvania Department of Environmental Protection announced its intent to not renew permits for publicly owned treatment works (POTW) that treat municipal wastewater to accept wastewater from

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

•	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.

•	Other post employment benefits and pension expenses increased primarily due to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs.

•	Royalties and production related taxes increased due to higher sales price of coal 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.

•	Demurrage charges were higher in the 2011 period due to increased export traffic at the Baltimore terminal.

•	Advertising and promotion expense increased $3 million in the period-to-period comparison due to additional campaigns initiated in the 2011 period.

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

•	Commission expense increased $2 million due to the increase in average sales price and additional tons sold for which a third party was owed a commission in the period-to-period comparison.

•	Consulting and professional services increased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.

•	Miscellaneous selling, general and administrative expenses increased $4 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 sold 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. Increased fuel and lubricant costs are related to higher fuel prices in the current period.

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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

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•	Production taxes average cost per thermal ton sold increased primarily due to the $5.11 per ton higher average sales price.

•	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.

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

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Labor and related benefits increased due to higher employee counts, higher non-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 sold 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.

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

•	Production taxes average cost per high volatile metallurgical ton sold increased due to the $5.17 per ton higher average sales price.

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

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•	Production taxes average cost per low volatile metallurgical ton sold increased due to the $45.49 per ton higher average sales price.

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Average operating supplies and maintenance costs per low volatile metallurgical ton sold 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 increased due to higher steel prices in the period-to-period comparison. In addition, costs were incurred in the 2011 period to increase the number of bore holes that were placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Increased rock dusting was primarily due to changes in regulations.

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Coal inventory volumes increased slightly at December 31, 2011 compared to December 31, 2010 and carrying value increased $5.09 per ton in the corresponding period. Coal inventory decreased 0.2 million tons at December 31, 2010 compared to December 31, 2009 and the carrying value of the inventory during the corresponding period increased $7.29 per ton. These changes in inventory caused a reduction in average operating cost per ton sold in the period-to-period comparison.

•	Power costs per low volatile metallurgical ton sold 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.

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

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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 were individually material. Closed and idle mine costs increased $5 million in the 2011 period due to a charge for an additional liability due to Pennsylvania stream remediation.

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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.

•	Other costs related to the coal segment decreased $7 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

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•	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 CONOL 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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•	Thermal coal unit costs were higher in 2010 as a result of lower cost mines, such as Bailey and Enlow Fork, selling coal in the high volatile metallurgical coal market. This impacted the thermal coal segment due to increased tons sold from higher cost mines.

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Labor costs increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-represented mines. Average employee counts also increased approximately 5% at our active mining operations. The additional employees were primarily due to the Shoemaker Mine resuming production in 2010 after being idled during 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional employees were also added in order to run our mines more safely, to prepare for the expected retirement of a significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwall advancement.

•	Health and retirement costs related to the active hourly work force increased due to higher contributions to the multiemployer 1974 pension trust that are required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America

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•	Power costs increased due to higher rates charged by utility companies and increased usage in the period-to-period comparison.

•	Operating costs also increased as a result of the 1.0 million ton decrease in inventory levels.

•	Reduced contract mining fees due to fewer contractors being retained to mine our reserves in the year ended December 31, 2010 compared to the 2009 period.

•	Average operating costs per thermal ton sold decreased due to higher tons sold. Fixed costs are allocated over higher tons resulting in decreased unit costs.

•	Employee wages and related expenses have increased due to additional employees in the selling, general and administrative area primarily related to support staff retained in the Dominion Acquisition which occurred on April 30, 2010 and additional hiring to support operations. Increased employee wages and related expenses are also related to additional actuarial expenses discussed above.

•	Commission expenses increased $5 million due to additional tons for which a third party was owed a commission compared to the prior year period.

•	Miscellaneous expenses have increased approximately $5 million. The increase was related to an additional $2 million for advertising and promotion fees, an additional $2 million for demurrage charges and an additional $1 million for various other items, none of which were individually material.

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In the year ended December 31, 2009, $12 million of income was recognized related to contracts with certain 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, 2010.

•	Gain on sales of assets attributable to the Other Coal segment were $9 million for the year ended December 31, 2010 compared to $16 million for the year ended December 31, 2009. The change was related to various transactions that occurred throughout both periods, none of which were individually material.

•	Coal royalty income from third parties was $15 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The decrease was related to lower tons mined by third parties from our coal reserves in the period-to-period comparison.

•	In the year ended December 31, 2009, mark-to-market adjustments for free standing coal sales options resulted in approximately a $2 million reversal of previously recognized unrealized losses. The reversal of the losses was primarily due to the decrease in market price of coal in 2009 compared to 2008. No such transactions existed in the year ended December 31, 2010.

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

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Closed and idle mine costs were $215 million for the year ended December 31, 2010 compared to $138 million for the year ended December 31, 2009. The increase of $77 million in closed and idle mine costs was primarily related to additional reclamation liabilities recognized at the Fola mining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mine plans, the reclamation liability associated with the Fola operation increased approximately $81 million. Additional closed and idle mine costs in 2010 were also related to a $14 million charge as a result of a change in the mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $18 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in 2010. Shoemaker Mine was idled throughout 2009 while the track haulage system was converted to a belt haulage system. This mine was in production throughout 2010.

•	Litigation expense of $25 million was recognized for the year ended December 31, 2010 related to a settlement that was reached in June 2010. The litigation was related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries.

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Cost of goods sold and other charges have increased approximately $13 million related to excess purchase price over appraised values for various land purchases that have been made throughout the year. Accounting guidance requires assets purchased to be recognized at the appraised value; synergies and related specific value to CONSOL Energy cannot be reflected as an asset. Various land deals in strategic areas for items such as refuse ponds, overland belts and various other key projects often require premiums over fair value, thus resulting in additional expense to CONSOL Energy at the time of the transaction.

•	Litigation settlement expense of $11 million was recognized for the year ended December 31, 2010 related to the sale of the Jones Fork Mining Complex.

•	Cost of goods sold and other charges have increased approximately $8 million due to various asset abandonments throughout the period, none of which were individually material. These abandonments primarily related to engineering work, permitting work and mapping work for miscellaneous projects that are no longer being pursued by the Company.

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Purchased coal consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. These costs were $40 million for the year ended December 31, 2010 compared to $46 million for the year ended December 31, 2009. The decrease of $6 million was primarily due to reduced purchased coal volumes in the period-to-period comparison.

•	Litigation expense of $17 million was recognized for the year ended December 31, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.

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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 expense is offset in freight revenue. Freight expense was $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23 million was primarily due to fewer tons shipped on CONSOL Energy freight contracts in the period-to-period comparison.

•	Other costs have increased $1 million primarily due to various contingent liabilities related to potential legal settlements as well as various other transactions that have occurred throughout both periods, none of which are individually material.

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The short-term incentive compensation program is designed to increase compensation to eligible employees when the gas segment reaches predetermined targets for safety, production and unit cost goals. Short-term incentive compensation expense is higher in 2010 due to a 13% increase in employee counts, as well as an increase in the short-term incentive compensation allocation to the gas segment. Additional employees in the total company general and administrative area were primarily related to support staff retained in the Dominion Acquisition,which closed on April 30, 2010 and additional hiring to support operations.

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Stock-based compensation is higher in the period-to-period comparison primarily due to the conversion of the CNX Gas performance share units to CONSOL Energy restricted stock units in the year ended December 31, 2009. The conversion resulted in a reduction of approximately $4 million of expense in 2009. Additional expense was also related to stock-based compensation allocated from CONSOL Energy to the gas segment in 2010. These increases were offset, in part, by the non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-in transaction. The expense previously recognized for these options was reversed on the gas segment. All stock-based compensation is now allocated from CONSOL Energy.

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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, but guarantees bank loans the entity holds related to its purchases of drilling rigs. CONSOL Energy is also the main customer of the third party, and based on analysis is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact is fully reversed in the noncontrolling interest line discussed below.

•	Banks fees are higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment.

•	Financing and acquisition fees are related to legal expenses for the special committee, formed during the CNX Gas take-in transaction, and are primarily related to the shareholder litigation.

•	The year ended December 31, 2009 includes $3 million of expense related to a contract buyout with a driller in order to mitigate idle rig charges in certain areas where drilling was not expected to increase in the near term.

•	Other corporate expense increased $2 million in the year-to-year comparison primarily due to unused firm transportation charges not being allocated to the operating gas segments and various other transactions that occurred throughout both periods, none of which were individually material.

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•	Interest expense of $198 million was incurred in the year ended December 31, 2010 compared to $24 million in the year ended December 31, 2009. The increase of $174 million was primarily attributable to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition, which closed on April 30, 2010.

•	Financing and acquisition fees of $62 million were incurred in the year ended December 31, 2010 primarily related to the equity and debt issuance that raised approximately $4.6 billion dollars. These fees also include costs related to

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•	Bank fees of $16 million were incurred in the year ended December 31, 2010 compared to $5 million in the year ended December 31, 2009. The increase of $11 million was primarily related to the refinanced revolving credit facility.

•	Fees related to the disposition of non-core assets of $3 million were incurred in the year ended December 31, 2010.

•	Various other corporate expenses were $21 million in the year ended December 31, 2010 compared to $18 million in the year ended December 31, 2009. The increase of $3 million was due to various transactions that occurred throughout both periods, none of which were individually material.

•	In the year ended December 31, 2010, there was $3 million of reduced expense related to an adjustment to assumptions used in the 2009 cease use of the Company's previous headquarter liability. The year ended December 31, 2009 included $13 million of expense related to the cease use of the facility. These transactions resulted in a $16 million improvement in the period-to-period comparison.

•	Severance payments of $4 million were incurred in the year ended December 31, 2009 related to various layoffs that were necessary due to the economic downturn that occurred.

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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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Operating cash flow increased $274 million in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-period comparison. The 2011 net income included an approximately $75 million reduction due to the abandonment of Mine 84 which is discussed further in Note 10—Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K. This reduction did not have a corresponding reduction to cash flows from operating activities because it was primarily related to the write-down of assets remaining at Mine 84 at the time of the abandonment, not cash obligations.

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

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•	On April 30, 2010, CONSOL Energy paid $3.470 billion for the Dominion Acquisition. See Note 2—Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.

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

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On September 30, 2011, CONSOL Energy received net proceeds of $485 million related to the Noble transaction, net proceeds of $190 million related to the Antero transaction, and net proceeds of $54 million related to the Hess transaction. See Note 2—Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.

•	On September 30, 2011, CONSOL Energy received a $67 million cash distribution from CONE Gathering LLC. See Note 2—Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.

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Total capital expenditures increased $228 million to $1.38 billion in the year ended December 31, 2011 compared to $1.15 billion in the year ended December 31, 2010. Capital expenditures for the gas segment increased $242 million due to the additional Marcellus Shale drilling in the period-to-period comparison. Capital expenditures for coal and other activities decreased $14 million in the period-to-period comparison. Face extension projects at various locations were lower by $87 million as a result of the majority of these projects being completed during the 2010 period, $13 million was incurred in the 2010 period as a result of a longwall shield lease buyout at Enlow Fork, and the 2011 period was lower by approximately $32 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011 and an approximate $42 million decrease in 2011 related to various other equipment expenditures throughout both periods. These reductions in coal and other capital were offset, in part by an approximate $122 million increase in expenditures related primarily to the ongoing development of the BMX Mine which is scheduled to begin production in early 2014, and a $38 million increase in 2011 related to the construction of the Northern West Virginia RO system.

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

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

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

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

•	In 2011, CONSOL Energy paid $15 million related to the solicitation of consents from the holders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020, and 6.375% Senior Notes due 2021. See Note 10—Long-Term Debt, in the Notes to the Audited Consolidated Financial Statements included Item 8 of this Form 10-K for additional details.

•	In 2011, CONSOL Energy paid outstanding borrowings of $155 million under the revolving credit facility. In 2010, CONSOL Energy paid $260 million under this facility.

•	Dividends of $96 million were paid in 2011 compared to $86 million in 2010. The increase was due to the 44.3 million additional shares issued on March 31, 2010 and also due to the increase of the regular annual dividend by 25%, or $0.10 per share, to $0.50 per share on October 27, 2011.

•	In 2011, proceeds of $250 million were received in connection with the issuance of $250 million of 6.375% senior

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•	In 2011, CNX Gas, a wholly-owned subsidiary, paid outstanding borrowings of $129 million under its revolving credit facility compared to receiving $71 million in 2010.

(a)	Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2012 contributions are expected to approximate $110 million.

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

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

•	An aggregate principal amount of $1.5 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.

•	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.

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

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

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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 U.S. 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 MGI's investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c)

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

(d)

This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI'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 MGI's investment management team. The smaller cap orientation of the strategy requires the investment

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(f)

This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest in 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 MGI's investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

(g)

This category invests in all cap companies operating in developed and emerging markets outside the U.S. 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 MGI's investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h)

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.

(i)

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 MGI's investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

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

(k)	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.

(l)	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.

(m)

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.

(n)

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

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(A)	Included in the Coal segment are sales of $662,109 to Xcoal Energy & Resources.

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

(C)	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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(D)	There were no sales to customers aggregating over 10% of total revenue in 2010.

(E)	Includes equity in earnings of unconsolidated affiliates of $13,846, $479 and $7,103 for Coal, Gas and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $21,463, $23,569 and $48,477 for Coal, Gas and All Other, respectively.

(G)	Total Gas includes $3,470,212 acquisition of Dominion Exploration and Production Business.

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*	Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.

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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)	Revisions are due to price, efficiencies in operations, and changes in the current five year plan as well as a comprehensive look into reservoir characterization and well performance.

(b)

Extensions and Discoveries are due to the drilling of proved undeveloped, probable and possible locations adhering to Security and Exchange Commission (SEC) guidelines on booking PUD locations if reliable technology can be demonstrated. The reliable technologies that were utilized include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis.  The statistical method utilized production performance from CONSOL Energy's and competitors' wells.  Geophysical data includes data from CONSOL Energy's wells, published documents, and state data-sites and was used to confirm continuity of the formation.

(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

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(a)	Gas equivalent reserves are expressed in billions of cubic feet equivalent (BCFE), determined using the ratio of 6 billion cubic feet of gas to 1 million barrels of oil.

(a)	During 2011, various exploration and development drilling and evaluations were completed. Approximately, $134,064 of capital was spent in the year ended December 31, 2011 related to undeveloped reserves that were transferred to developed.

(b)

Included in proved undeveloped reserves at December 31, 2011 are approximately 121,003 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 for many years past, 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. During 2011, three wells were removed from the previous year-end schedule. One of these wells was connected and is now producing while two wells were determined to be dry or uneconomical to pursue and expensed.

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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

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBIT INDEX

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