CONSOL Energy
Annual Report 2011

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 __________________________________________________FORM 10-K __________________________________________________ (Mark One)xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.For the fiscal year ended December 31, 2011ORoTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from to Commission file number: 001-14901 __________________________________________________CONSOL Energy Inc.(Exact name of registrant as specified in its charter)Delaware 51-0337383(State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification No.)1000 CONSOL Energy DriveCanonsburg, PA 15317-6506(724) 485-4000(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices) __________________________________________________ Securities registered pursuant to Section 12(b) of the Act:Title of each class Name of exchange on which registeredCommon Stock ($.01 par value) New York Stock ExchangePreferred Share Purchase Rights New York Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act: None__________________________________________________Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No oIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No xIndicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes x No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submittedand posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required tosubmit and post such files). Yes x No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best ofregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. xIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of“large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller Reporting Company oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No xThe aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2011, the last business day of the registrant's most recently completedsecond fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was $10,963,933,121.The number of shares outstanding of the registrant's common stock as of January 25, 2012 is 227,093,353 shares.DOCUMENTS INCORPORATED BY REFERENCE:Portions of CONSOL Energy's Proxy Statement for the Annual Meeting of Shareholders to be held on May 1, 2012, are incorporated by reference in Items 10, 11, 12, 13 and14 of Part III. TABLE OF CONTENTS PagePART I ITEM 1.Business4ITEM 1A.Risk Factors37ITEM 1B.Unresolved Staff Comments52ITEM 2.Properties52ITEM 3.Legal Proceedings52ITEM 4.Mine Safety and Health Administration Safety Data52 PART II ITEM 5.Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities53ITEM 6.Selected Financial Data54ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of Operations58ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk108ITEM 8.Financial Statements and Supplementary Data110ITEM 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosures179ITEM 9A.Controls and Procedures179ITEM 9B.Other Information181 PART III ITEM 10.Directors and Executive Officers of the Registrant181ITEM 11.Executive Compensation182ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters182ITEM 13.Certain Relationships and Related Transactions and Director Independence182ITEM 14.Principal Accounting Fees and Services182 PART IV ITEM 15.Exhibits and Financial Statement Schedules183SIGNATURES1902FORWARD-LOOKING STATEMENTSWe are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harborprovisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception ofhistorical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act)that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place unduereliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning thetiming and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,”“expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statementswhich include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; wedisclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based theseforward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations andassumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies anduncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, amongother matters, the following:•deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial marketscause 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 positionbecause 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 impactfinancial 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 qualityservices 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 wastesgenerated 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 withour 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 gaswell;•the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or currentcoal and gas operations;3•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 lossessuffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans whichwe 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 aplan year;•acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businessesand their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we mayhave 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 financialposition;•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 Securitiesand Exchange Commission.PART IITEM 1.BusinessCONSOL Energy's Business IntroductionCONSOL Energy safely and responsibly produces coal and natural gas for global energy and raw material markets, which include the electric powergeneration industry and the steelmaking industry. During the year ended December 31, 2011, we produced 62.6 million tons of high-British thermal unit(Btu) bituminous coal from 12 mining complexes in the United States. During this same period, our natural gas production totaled 153.5 net billion cubic feetequivalent (Bcfe) from approximately 15,000 gross natural gas wells primarily in Appalachia.Additionally, we provide energy services, including river and dock services, terminal services, industrial supply services, water services and landresource management services.CONSOL Energy's HistoryCONSOL Energy was incorporated in Delaware in 1991. Our coal operations began in 1864. CONSOL Energy's beginnings as the “ConsolidationCoal Company” in Western Maryland led to growth and expansion through all major coal producing regions in the United States. CONSOL Energy enteredthe natural gas business in the 1980s to increase the safety and efficiency of our coal mines by capturing methane from coal seams prior to mining, whichmakes the mining process safer and more efficient. Over the past five years, CONSOL Energy's natural gas business has grown by over 164% to produce153.5 net Bcfe in 2011. This business has grown from coalbed methane production in Virginia into other unconventional production, such as MarcellusShale, in the Appalachian basin. This growth was accelerated with the 2010 asset acquisition of the Appalachian E&P business of Dominion Resources, Inc.(Dominion Acquisition). Subsequently, in August and September42011, we announced two strategic joint ventures, one with Noble Energy, Inc. (Noble) and one with a subsidiary of Hess Corporation (Hess). These jointventures will allow the acceleration of development of the assets acquired in the Dominion Acquisition and will focus on the development of our Marcellus andUtica asset holdings.CONSOL Energy's StrategyCONSOL Energy's strategy is to continue to build the Company into a large integrated energy company.CONSOL Energy defines itself through its core values which are:•Safety•Compliance•Continuous ImprovementThese values are the foundation of CONSOL Energy's identity and are the basis for how management defines continued success. We believe CONSOLEnergy's rich resource base, coupled with these core values allow CONSOL Energy to create value for the long-term. The electric power industry generates overtwo-thirds of its output by burning coal or natural gas, the two fuels we produce. We believe that the use of coal and natural gas will continue for many yearsas the principal fuel sources for electricity in the United States. Additionally, we believe that as worldwide economies grow, the demand for electricity fromfossil fuels will grow as well, resulting in expansion of worldwide demand for our coal and natural gas.U.S. ELECTRIC SUPPLY by ENERGY SOURCEIn percent of total Actuals Preliminary Projected 2009 2010 2011 2015Coal 44.4 44.8 42.9 42.3Natural Gas 23.3 23.9 24.4 23.5Nuclear 20.2 19.6 19.1 19.7Conventional Hydro 6.8 6.2 7.6 7.7Renewables 3.7 4.1 4.7 5.3Others 1.6 1.4 1.3 1.5________________Source: U.S. Energy Information AdministrationAlthough coal is projected to lose a small percentage of market share in the U.S. electric generation market, we believe that our efficient, long-lived, wellcapitalized longwall mines that operate near major U.S. population centers will continue to maintain their existing market share in the U.S. thermal coalmarket.We expect natural gas to become a significant contributor to the domestic electric generation mix as well as industrial segments of the U.S. economy.Also, natural gas may potentially become a significant contributor to the transportation market. Our increasing gas production will allow CONSOL Energy toparticipate in these markets.The following charts show CONSOL Energy's recent growth in international coal sales and metallurgical coal sales.5CONSOL Energy's Capital Expenditure BudgetCONSOL Energy's 2012 capital expenditure budget totals $1.5 billion which is an increase from the $1.4 billion invested in 2011. The budget includes$676 million for coal, $623 million for gas, $135 million for water, and $110 million for other. The budget reflects the plan to invest in our highest rate ofreturn projects: the organic opportunities in coal, gas, and liquid hydrocarbons. CONSOL Energy has the ability to adjust these planned investments shouldcircumstances warrant.The table below categorizes the 2011 actual capital expenditures and the planned 2012 capital expenditure budget. 2011 2012 Actual Capital Forecasted Capital Expenditures ExpendituresCoal (in millions) Maintenance of Production $243 $277 Efficiency Projects (e.g., overland belts) $183 $146 Increases in Production (e.g., Bailey Mine Expansion) $114 $203 Safety $18 $50Total Coal $558 $676 Gas Marcellus $427 $473 Utica $3 $53 CBM $130 $65 Other $102 $32Total Gas $662 $623 Other Water $49 $135 Transportation (e.g., Baltimore Terminal; barges) $28 $30 Coal Land $73 $55 Other $12 $25Total Other $162 $245 Total Capital $1,382 $1,5446CONSOL Energy's OperationsThe following map provides the location of CONSOL Energy's coal and gas operations by region:CONSOL Energy Operations Highlights – CoalWe have consistently ranked among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. Weproduced 62.6 million tons of coal in 2011. Our production of 62.4 million tons of coal in 2010 accounted for approximately 6% of the total tons produced inthe United States and almost 14% of the total tons produced east of the Mississippi River during 2010, the latest year for which statistics are available.CONSOL Energy holds approximately 4.5 billion tons of proved and probable coal reserves located in northern Appalachia (62%), the mid-western UnitedStates (17%), central Appalachia (15%), the western United States (4%), and in western Canada (2%) at December 31, 2011. We are one of the premier coalproducers in the United States by several measures:•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.7The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2010, the latest year forwhich statistics are available.MAJOR U.S. UNDERGROUND COAL MINES–2010In millions of tons Mine Name Operating Company ProductionBailey CONSOL Energy 10.9Enlow Fork CONSOL Energy 10.2McElroy CONSOL Energy 10.1Twenty Mile Peabody Energy Subsidiary 7.1Powhatan No. 6 The Ohio Valley Coal Company (Murray) 6.5SUFCO Arch Coal, Inc. 6.2Century American Energy Corp. (Murray) 6.2Loveridge CONSOL Energy 5.9Cumberland Cumberland Coal Resources (Alpha) 5.8Warrior Warrior Coal, LLC (Alliance) 5.8River View River View Coal, LLC (Alliance) 5.8Mach No. 1 Williamson Energy, LLC (Foresight Energy) 5.8Robinson Run CONSOL Energy 5.5San Juan BHP Billiton 5.0Emerald Emerald Coal Resources (Alpha) 4.9West Elk Arch Coal, Inc. 4.8Buchanan CONSOL Energy 4.7Blacksville No. 2 CONSOL Energy 4.5Mountaineer II / Mtn. Laurel Arch Coal, Inc. 4.4New Era American Energy Corp. (Murray) 4.3________________Source: National Mining Association, EIACONSOL Energy continues to derive a substantial portion of its revenue from sales of coal to electricity generators in the United States. In 2011, sales todomestic electric generators comprised approximately 60% of coal revenue and 48% of total revenue. The largest customer represented approximately 15% ofcoal revenue and 12% of total revenue. The largest four customers represent approximately 40% of coal revenue and over 30% of total revenue. As natural gasrevenue continues to grow, we expect the relative contribution of our largest coal customers to diminish.CONSOL Energy Operations Highlights – GasCONSOL Energy is a leader in developing unconventional gas resources including the development of coalbed methane (CBM) production in theEastern United States. Our gas operations produced 153.5 net Bcfe made up of a combination of CBM (60%), which is gas that resides in coal seams,natural gas from various shallow oil and gas sites (21%), natural gas from the Marcellus Shale (18%), and other unconventional reservoirs (1%). CONSOLEnergy reported estimated net proved gas reserves of 3.5 trillion cubic feet. These reserves were made up of CBM (50%), Marcellus (25%), shallow oil andgas (21%) and other (4%). CONSOL Energy controls considerable resource positions in other unconventional shale plays including: Chattanooga, NewAlbany, Utica, Huron and other shales.Our position as a gas producer is highlighted by several measures:•We are one of the largest natural gas producers in Appalachia with approximately 15,000 total gross wells in Appalachia comprising 8% of allAppalachian wells based on 2009 U.S. Energy Information Administration data, the latest year for which statistics are available.8•We are one of the largest CBM producers, with production equal to approximately 35% of total Appalachian CBM production and 59% ofNorthern Appalachian production (excluding Alabama) based on 2009 U.S. Energy Information Administration data, the latest year for whichstatistics 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 operateover 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 NewAlbany Shales.In 2011, CONSOL Energy's sales of CBM gas comprised approximately 62% of gas revenue and 8% of total revenue. Sales of Marcellus gas for thesame time period comprised approximately 16% of gas revenue and 2% of total revenue, and sales of shallow oil and gas comprised 21% of gas revenue and3% of total revenue.Coal CompetitionThe United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. CONSOL Energy competesagainst other large producers and hundreds of small producers in the United States and overseas. The five largest producers are estimated by the 2010National Mining Association Survey to have produced approximately 58% (based on tonnage produced) of the total United States production in 2010. TheU.S. Department of Energy reported 1,285 active coal mines in the United States in 2010, the latest year for which government statistics are available.Demand for our coal by our principal customers is affected by many factors including:•the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil andrenewable energy sources, such as hydroelectric power or wind;•environmental and government regulation;•coal quality;•transportation costs from the mine to the customer; and•the reliability of fuel supply.Continued demand for CONSOL Energy's coal and the prices that CONSOL Energy obtains are affected by demand for electricity, technologicaldevelopments, environmental and governmental regulation, and the availability and price of competing coal and alternative fuel supplies. We sell coal to foreignelectricity generators and to the more specialized metallurgical coal markets, both of which are significantly affected by international demand and competition.Natural Gas CompetitionThe United States natural gas industry is highly competitive. CONSOL Energy competes with other large producers, thousands of small producers aswell as pipeline imports from Canada and Liquefied Natural Gas (LNG) from around the globe. According to data from the Natural Gas Supply Associationand the U.S. Department of Energy, the five largest producers of natural gas produced less than 21% of the total U.S. production in the third quarter of 2011.The U.S. Department of Energy reported almost 500,000 producing natural gas wells in the United States in 2009, the latest year for which governmentstatistics are available.CONSOL Energy's gas operations are primarily in the eastern United States. We believe that the gas market is highly fragmented and not dominated byany single producer. We believe that competition within our market is based primarily on natural gas commodity trading fundamentals and pipelinetransportation availability to the various markets.Continued demand for CONSOL Energy's natural gas and the prices that CONSOL Energy obtains are affected by demand for electricity,environmental and government regulation, technological developments and the availability and price of competing alternative fuel supplies.Industry SegmentsFinancial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years endedDecember 31, 2011, 2010 and 2009 is included in Note 25–Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 ofthis Form 10-K and incorporated herein.DETAIL COAL OPERATIONSMining Complexes9The following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with eachCONSOL ENERGY MINING COMPLEXESProven and Probable Assigned and Accessible Coal Reserves as of December 31, 2011 and 2010 Recoverable Recoverable Average As Received Heat Reserves(2) Reserves Seam Value(1) Tons in (tons in) Reserve Coal Thickness (Btu/lb) Owned Leased Millions Millions)Mine/Reserve Location Class Seam (feet) Typical Range (%) (%) 12/31/2011 12/31/2010ASSIGNED–OPERATING Thermal Reserves Enlow Fork(4) Enon, PA Assigned Pittsburgh 5.4 12,940 12,860 –13,060 100% —% 28.5 38.7 Accessible Pittsburgh 5.3 12,900 12,830 –13,000 77% 23% 204.5 197.9Bailey(4) Enon, PA Assigned Pittsburgh 5.5 12,950 12,860 –13,060 45% 55% 101.6 112.3 Accessible Pittsburgh 5.6 12,900 12,830 –13,000 90% 10% 334.4 334.3McElroy Glen Easton,WV Assigned Pittsburgh 5.7 12,570 12,450 –12,650 94% 6% 105.7 7.4 Accessible Pittsburgh 5.9 12,530 12,410 –12,610 95% 5% 90.0 153.1Shoemaker Moundsville,WV Assigned Pittsburgh 5.6 12,200 11,700 –12,300 100% —% 68.3 44.5 Accessible Pittsburgh — — — —% —% — 27.8Loveridge Metz, WV Assigned Pittsburgh 7.5 13,000 12,850 –13,150 76% 24% 26.4 32.0 Accessible Pittsburgh 7.6 13,000 12,820 –13,100 95% 5% 13.6 13.6Robinson Run Shinnston, WV Assigned Pittsburgh 7.4 12,950 12,600 –13,300 86% 14% 46.8 52.7 Accessible Pittsburgh 6.8 12,940 12,600 –13,300 55% 45% 156.7 156.7Blacksville #2(4) Wana, WV Assigned Pittsburgh 6.7 13,020 12,800 –13,150 81% 19% 20.3 24.7 Accessible Pittsburgh 6.9 13,000 12,800 –13,100 99% 1% 16.5 16.5Harrison Resources(3) Cadiz, OH Assigned Multiple 4.5 11,570 11,350 –11,850 100% —% 6.7 7.1Amvest-Fola Complex(4) Bickmore, WV Assigned Multiple 4.3 12,380 12,250 –12,550 88% 12% 92.2 53.3Miller Creek Complex Delbarton, WV Assigned Multiple 3.3 12,000 11,600 –12,650 4% 96% 5.6 9.0 Metallurgical Reserves Buchanan Mavisdale, VA Assigned Pocahontas 3 5.7 13,900 13,700 –14,200 22% 78% 58.0 63.7 Accessible Pocahontas 3 6.0 13,930 13,650 –14,150 10% 90% 37.0 37.0Western Allegheny-KnobCreek(3) YoungTownship, PA Assigned UpperKittanning 3.2 13,050 13,000 –13,100 100% —% 2.3 2.4Total Assigned Operating andAccessible 1,415.1 1,384.710_____________(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 foraccessible reserves is based on the same mining and processing methods as for the assigned reserves with adjustments made based on the variability found inexploration 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 rocklying 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 laboratorytesting 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 thecoal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor dothe calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams thatare 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 equalCONSOL 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.Excluded from the table above are approximately 179.3 million tons of reserves at December 31, 2011 that are assigned to projects that have notproduced coal in 2011. These assigned reserves are in the Northern Appalachia (northern West Virginia and Pennsylvania), Central Appalachia (Virginia andeastern Kentucky), the Western U.S. (Utah) and Illinois Basin (Illinois) regions. These reserves are approximately 60% owned and 40% leased.CONSOL Energy assigns coal reserves to each of our mining complexes. The amount of coal we assign to a mining complex generally is sufficient tosupport mining through the duration of our current mining permit. Under federal law, we must renew our mining permits every five years. All assignedreserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.In addition, our mining complexes may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible.Accessible reserves are proven and probable unassigned reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of thecomplex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend orto continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.Some reserves may be accessible by more than one mining complex because of the proximity of many of our mining complexes to one another. In thetable above, the accessible reserves indicated for a mining complex are based on our review of current mining plans and reflect our best judgment as to whichmining complex is most likely to utilize the reserve.Assigned and unassigned coal reserves are proven and probable reserves which are either owned or leased. The leases have terms extending up to 30years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimumroyalties. Under current mining plans, assigned reserves reported will be mined out within the period of existing leases or within the time period of probablelease renewal periods.Coal ReservesAt December 31, 2011, CONSOL Energy had an estimated 4.5 billion tons of proven and probable reserves. Reserves are the portion of the proven andprobable tonnage that meet CONSOL Energy's economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio.Generally, these reserves would be commercially mineable at year-end price and cost levels.Reserves are defined in Securities and Exchange Commission (SEC) Industry Guide 7 as that part of a mineral deposit which could be economicallyand legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:Proven (Measured) Reserves- Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drillholes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced soclose and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.Probable (Indicated) Reserves- Reserves for which quantity and grade and/or quality are computed from information similar to that used forproven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart11or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assumecontinuity between points of observation.Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (CoalResource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Estimates forproven reserves are based on points of observation that are equal to or less than 0.5 miles apart. Estimates for probable reserves have a moderate degree ofgeologic assurance and are computed from points of observation that are between 0.5 to 1.5 miles apart.An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because of the well-known continuityof this seam, spacing requirements are 3,000 feet or less for proven reserves and between 3,000 and 8,000 feet for probable reserves.CONSOL Energy's estimates of proven and probable reserves do not rely on isolated points of observation. Small pods of reserves based on a singleobservation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.Our reserve estimates are predicated on information obtained from our ongoing exploration drilling and in-mine sampling programs. Data including coalseam elevation, thickness, and, where samples are available, coal quality is entered into a computerized geological database. This information is thencombined with data on ownership or control of the mineral and surface interests to determine the extent of reserves in a given area. Reserve estimates includemine recovery rates that reflect CONSOL Energy's experience in various types of underground and surface coal mines.CONSOL Energy's reserve estimates are based on geological, engineering and market data assembled and analyzed by our staff of geologists andengineers located at individual mines, operations offices and at our principal office. The reserve estimates are reviewed and adjusted annually to reflectproduction of coal from reserves, analysis of new engineering and geological data, changes in property control, modification of mining methods and otherfactors. Information, including the quantity and quality of reserves, coal and surface control, and other information relating to CONSOL Energy's coal reserveand land holdings, is maintained through a system of interrelated computerized databases.Our estimate of proven and probable coal reserves has been determined by CONSOL Energy's geologists and mining engineers. Our coal reserves areperiodically reviewed by an independent third party consultant. The independent consultant has reviewed the procedures used by us to prepare our internalestimates, verified the accuracy of our property reserve estimates and retabulated reserve groups according to standard classifications of reliability.CONSOL Energy's proven and probable coal reserves fall within the range of commercially marketed coals in the United States. The marketability ofcoal depends on its value-in-use for a particular application, and this is affected by coal quality, such as, sulfur content, ash and heating value. Modernpower plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy's coals can be marketed for theelectric power generation industry. Additionally, the growth in worldwide demand for metallurgical coals allows some of our proven and probable coalreserves, currently classified as thermal coals, that possess certain qualities to be sold as metallurgical coal. The addition of this cross-over market addsadditional assurance to CONSOL Energy that all of its proven and probable coal reserves are commercially marketable. 12The following table sets forth our unassigned proven and probable reserves by region:CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2011 and 2010 Recoverable Recoverable Reserves(2) Reserves Tons in (tons in As Received Heat Owned Leased Millions Millions)Coal Producing Region Value(1) (Btu/lb) (%) (%) 12/31/2011 12/31/2010Northern Appalachia (Pennsylvania, Ohio, Northern WestVirginia) 11,400 – 13,500 72% 28% 1,448.1 1,412.2Central Appalachia (Virginia, Southern West Virginia,Eastern Kentucky) 11,300 – 14,200 51% 49% 421.3 327.7Illinois Basin (Illinois, Western Kentucky, Indiana) 11,500 – 11,900 44% 56% 750.7 777.9Western U.S. (Wyoming) 9,225 95% 5% 142.2 169.1Western Canada (Alberta) 12,400 – 12,900 —% 100% 102.7 77.9Total 61% 39% 2,865.0 2,764.8_______________(1)The heat value estimates for Northern Appalachian and Central Appalachian unassigned coal reserves include adjustments for moisture that may beadded during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently inuse are used for these estimates. The heat value estimates for the Illinois Basin, Western U.S. and Western Canada unassigned reserves are basedprimarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lyingabove 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 laboratorytesting 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 thecoal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do thecalculations include adjustments for dilution from rock lying above or below the coal seam.The following table summarizes our proven and probable reserves as of December 31, 2011 by region and type of coal or sulfur content (sulfur contentper million British thermal units). Proven and probable reserves include both assigned and unassigned reserves. The table classifies bituminous coal by rank.Rank (High volatile A, B and C) of bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and lowvolatile which are classified on the basis of fixed carbon and volatile matter. Coal is ranked by the degree of alteration it has undergone since the initialdeposition of the organic material. The lowest ranked coal, lignite, has undergone less transformation than the highest ranked coal, anthracite. From the lowestto the highest rank, the coals are: lignite; sub-bituminous; bituminous and anthracite. The ranking is determined by measuring the fixed carbon to volatilematter ratio and the heat content of the coal. As rank increases, the amount of fixed carbon increases, volatile matter decreases, and heat content increases.Bituminous coals are further characterized by the amount of volatile matter present. Bituminous coals with high volatile matter content are also ranked. Highvolatile “A” bituminous coals have higher heat content than high volatile “C” bituminous coals. These characterizations of coal allow a user to predict thebehavior of a coal when burned in a boiler to produce heat or when it is heated in the absence of oxygen to produce coke for steel production.13CONSOL Energy Proven and Probable Recoverable Coal ReservesBy Producing Region and Product (In Millions of Tons) As of December 31, 2011 ≤ 1.20 lbs. > 1.20 ≤ 2.50 lbs. > 2.50 lbs. S02/MMBtu S02/MMBtu S02/MMBtu Percent Low Med High Low Med High Low Med High ByBy Region Btu Btu Btu Btu Btu Btu Btu Btu Btu Total RegionNorthern Appalachia: Metallurgical: High Vol A Bituminous — — — — — 164.6 — — — 164.6 3.7%Thermal: High Vol A Bituminous — — — — — 111.3 61.8 115.5 2,250.1 2,538.7 56.9% Low Vol Bituminous — — — — — 33.6 — — — 33.6 0.8% Region Total — — — — — 309.5 61.8 115.5 2,250.1 2,736.9 61.4%Central Appalachia: Metallurgical: High Vol A Bituminous — — 32.7 — — 29.9 — — 1.3 63.9 1.4% Med Vol Bituminous — 3.0 143.6 — — 2.9 — — — 149.5 3.4% Low Vol Bituminous — — 114.1 — — 26.3 — — — 140.4 3.1%Thermal: High Vol A Bituminous 34.9 80.8 2.8 44.4 126.0 2.4 9.4 15.0 — 315.7 7.1% Region Total 34.9 83.8 293.2 44.4 126.0 61.5 9.4 15.0 1.3 669.5 15.0%Midwest-Illinois Basin: Thermal: High Vol B Bituminous — — — — 65.1 — — 444.9 — 510.0 11.4% High Vol C Bituminous — — — — 159.5 — 108.3 — — 267.8 6.0% Region Total — — — — 224.6 — 108.3 444.9 — 777.8 17.4%Northern Powder River Basin: Thermal: Sub Bituminous B — — 142.2 — — — — — — 142.2 3.2% Region Total — — 142.2 — — — — — — 142.2 3.2%Utah-Emery Field: Thermal: High Vol B Bituminous — 17.9 — — 12.3 — — — — 30.2 0.7% Region Total — 17.9 — — 12.3 — — — — 30.2 0.7%Western Canada: Metallurgical: Med Vol Bituminous 30.2 72.6 — — — — — — — 102.8 2.3% Region Total 30.2 72.6 — — — — — — — 102.8 2.3% Total Company 65.1 174.3 435.4 44.4 362.9 371.0 179.5 575.4 2,251.4 4,459.4 100.0% Percent of Total 1.5% 3.9% 9.8% 1.0% 8.1% 8.3% 4.0% 12.9% 50.5% 100.0% 14The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound).The table also classifies bituminous coals as high, medium and low volatile which is based on fixed carbon and volatile matter.CONSOL Energy Proven and Probable Recoverable Coal ReservesBy Product (In Millions of Tons) As of December 31, 2011 ≤ 1.20 lbs. > 1.20 ≤ 2.50 lbs. > 2.50 lbs. S02/MMBtu S02/MMBtu S02/MMBtu Low Med High Low Med High Low Med High Percent ByBy Region Btu Btu Btu Btu Btu Btu Btu Btu Btu Total ProductMetallurgical: High Vol A Bituminous — — 32.7 — — 194.5 — — 1.3 228.5 5.1% Med Vol Bituminous 30.2 75.6 143.6 — — 2.9 — — — 252.3 5.7% Low Vol Bituminous — — 114.1 — — 26.3 — — — 140.4 3.1% Total Metallurgical 30.2 75.6 290.4 — — 223.7 — — 1.3 621.2 13.9%Thermal: High Vol A Bituminous 34.9 80.8 2.8 44.4 126.0 113.7 71.2 130.5 2,250.1 2,854.4 64.0% High Vol B Bituminous — 17.9 — — 77.4 — — 444.9 — 540.2 12.1% High Vol C Bituminous — — — — 159.5 — 108.3 — — 267.8 6.0% Low Vol Bituminous — — — — — 33.6 — — — 33.6 0.8% Sub Bituminous B — — 142.2 — — — — — — 142.2 3.2% Total Thermal 34.9 98.7 145.0 44.4 362.9 147.3 179.5 575.4 2,250.1 3,838.2 86.1% Total 65.1 174.3 435.4 44.4 362.9 371.0 179.5 575.4 2,251.4 4,459.4 100.0% Percent of Total 1.5% 3.9% 9.8% 1.0% 8.1% 8.3% 4.0% 12.9% 50.5% 100.0% The following table categorizes the relative Btu values (low, medium and high) for each of CONSOL Energy's producing regions in Btu's per pound ofcoal.Region Low Medium HighNorthern, Central Appalachia and Canada < 12,500 12,500 – 13,000 > 13,000Midwest Appalachia < 11,600 11,600 – 12,000 > 12,000Northern Powder River Basin < 8,400 8,400 – 8,800 > 8,800Colorado and Utah < 11,000 11,000 – 12,000 > 12,000Title to coal properties that we lease or purchase and the boundaries of these properties are verified by law firms retained by us at the time we lease oracquire the properties. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planneddevelopment or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to minereserves could be adversely affected.15The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount ofincome (net of related expenses) we received from royalty payments for the years ended December 31, 2011, 2010 and 2009. Total Total Total Royalty Coal Royalty Tonnage Acreage IncomeYear (in thousands) Leased (in thousands)2011 8,488 289,833 $17,9982010 8,606 226,524 $14,0732009 11,403 232,181 $16,448Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable reserves do not includereserves attributable to properties that we lease to third parties.Compliance Compared to Non-Compliance CoalCoals are sometimes characterized as compliance or non-compliance coal. The term "compliance coal," as it is commonly used in the coal industry,refers to compliance only with former national sulfur dioxide emissions standards and indicates that when burned, the coal will produce emissions that willnot exceed 1.2 pounds of sulfur dioxide per million British thermal units (1.2lb S02/MM Btu). A coal considered a compliance coal for meeting this formersulfur dioxide standard may not meet an emission standard for a different pollutant such as mercury, and may not even meet newer sulfur emission standardsfor all power plants. Clean air regulations that further restrict sulfur dioxide emissions will likely significantly reduce the amount of coal that can be usedwithout post-combustion emission control technologies. Currently, a compliance coal will meet the power plant emission standard of 1.2 lb S02/MM Btu offuel consumed. At December 31, 2011, approximately 0.7 billion tons, or 15%, of our coal reserves met that standard as a compliance coal. It is likely that,within several years, no coal will be "compliant" because federal regulations will require emissions-control technology to be used regardless of the coal's sulfurcontent. In many cases, our customers have responded to ever-tightening emissions requirements by retrofitting flue gas desulfurization systems (scrubbers) toexisting power plants. Because these systems remove sulfur dioxide before it is emitted into the atmosphere, those customers are less concerned about the sulfurcontent of our coal. As a result of a 1998 court decision forcing the establishment of mercury emissions standards for power plants, the Environmental Protection Agency(EPA) was required to promulgate a regulatory program for controlling mercury. CONSOL Energy coals have mercury contents typical for their rank andlocation (approximately 0.07-0.15 parts mercury on a dry coal basis). Since CONSOL Energy coals have high heating values, they have lower mercurycontents on a weight per energy basis (typically measured in pounds per trillion Btu) than lower rank coals at a given mercury concentration. Easternbituminous coals also tend to produce a greater proportion of flue gas mercury in the ionic or oxidized form (which is more easily captured by scrubbersinstalled for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. Both high rank and low rank coals are alsoamenable to other methods of controlling mercury emissions, such as by powder activated carbon injection. The EPA's proposed Clean Air Mercury Rule wasvacated by a federal court ruling. The EPA is currently developing new regulations to control multiple hazardous air pollutants, including mercury, from coal-fired plants, the so-called MACT Rule, which is expected to be finalized in 2014. Some states have already adopted a control program for mercury emissionsfrom coal-fired power plants.ProductionIn the year ended December 31, 2011, 94% of CONSOL Energy's production came from underground mines and 6% from surface mines. Where thegeology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year endedDecember 31, 2011, 91% of our production came from mines equipped with longwall mining systems. Underground longwall systems are highlymechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and canachieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readilysuitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at a low incremental cost.16The following table shows the production, in millions of tons, for CONSOL Energy's mines in the years ended December 31, 2011, 2010 and 2009, thelocation of each mine, the type of mine, the type of equipment used at each mine, method of transportation and the year each mine was established or acquiredby us. Tons Produced Year Mine Mining (in millions) EstablishedMine Location Type Equipment Transportation 2011 2010 2009 or AcquiredThermal McElroy Glen Easton, WV U LW/CM CB B 9.3 10.1 9.9 1968Bailey Enon, PA U LW/CM R R/B 8.8 9.8 10.4 1984Enlow Fork Enon, PA U LW/CM R R/B 8.3 9.1 11.1 1990Robinson Run Shinnston, WV U LW/CM R CB 5.6 5.5 5.6 1966Loveridge Metz, WV U LW/CM R T 5.5 5.9 6.0 1956Shoemaker(2) Moundsville, WV U LW/CM B 5.1 3.9 0.4 1966Blacksville #2(1) Wana, WV U LW/CM R R/B T 4.2 4.5 3.8 1970Miller Creek Complex(3) Delbarton, WV U/S CM/S/L R T 2.8 3.0 3.2 2004AMVEST–Fola Complex(1)(3) Bickmore, WV U/S A/S/L/CM R T 2.1 1.9 3.0 2007Harrison Resources(3)(4) Cadiz, OH S S/L R T 0.4 0.5 0.4 2007Emery(1) Emery Co., UT U/S CM T — 1.0 1.2 1945Buchanan–Thermal(1) Mavisdale, VA U LW/CM R — 0.2 0.7 1983Jones Fork Complex(1)(3)(5) Mousie, KY U/S CM/S/L R T — 0.1 1.1 1992Mine 84(1)(6) Eighty Four, PA U LW/CM R R/B T — — 0.5 1998High Volatile Metallurgical Bailey–Met Enon, PA U LW/CM R R/B 2.1 1.2 — 1984Enlow Fork–Met Enon, PA U LW/CM R R/B 1.8 1.1 — 1990Robinson Run–Met Shinnston, WV U LW/CM R CB 0.4 — — 1966Blacksville #2(1)–Met Wana, WV U LW/CM R R/B T 0.1 — — 1970Western Allegheny–Knob Creek(3)(4) Young Township, PA U CM R T 0.1 0.1 — 2010Loveridge–Met Metz, WV U LW/CM R T 0.1 — — 1956AMVEST–Fola Complex(1)(3)–Met Bickmore, WV U/S A/S/L/CM R T 0.1 — — 2007AMVEST–Terry Eagle Complex(1)(3)–Met Jodie, WV U/S CM/A/S/L R T 0.1 — — 2007Low Volatile Metallurgical Buchanan(1) Mavisdale, VA U LW/CM R T 5.7 4.5 2.1 1983Total 62.6 62.4 59.4 ___________A–AugerS–SurfaceU–UndergroundLW–LongwallCM–Continuous MinerS/L–Stripping Shovel and Front End LoadersR–RailB–BargeR/B–Rail to BargeT–TruckCB–Conveyor Belt(1)–Mine was idled for part of the year(s) presented due to market conditions.(2)–Mine was idled throughout most of 2009 due to converting from track haulage, to more efficient belt haulage to remove coal from the mine.(3)–Harrison Resources, Miller Creek Complex, AMVEST–Fola Complex, AMVEST–Terry Eagle Complex, Jones Fork Complex and Western Allegheny–Knob Creek includefacilities operated by independent contractors.(4)–Production amounts represent CONSOL Energy's 49% ownership interest.(5)–Complex was sold in March 2010.(6)–Mine 84 was permanently idled in 2011.17Coal Capital ProjectsCONSOL Energy anticipates investing $277 million for maintenance-of-production projects and $203 million to projects such as the BMX Mine (seebelow for BMX description.) Also, $146 million is planned for efficiency improvements such as the overland belt at Enlow Fork Mine and $50 million isplanned for health and safety items.In 2011, capital projects included the continued development of the BMX Mine. This project is expected to add 5 million tons a year of high-qualityPittsburgh seam coal, which will be sold in either the high-volatile metallurgical or thermal markets. An extension of Bailey Mine began in 2009 andproduction from the first longwall panel is expected to start in early 2014. The total cost of the project is expected to be approximately $662 million of whichapproximately $132 million was incurred in 2011. As of December 31, 2011, total project-to-date expenditures were approximately $175 million. Includedwithin the scope of this project are certain surface facility upgrades at the Bailey Preparation Plant which are necessary in order for the plant to process theadditional coal from the BMX Mine. These upgrades include the construction of several new raw and clean coal silos, expansion of existing railroad facilities,and installation of additional raw coal material handling systems.In 2011, capital projects included the continued development of the Amonate Complex. This project is expected to add 400 - 600 thousand tons a year ofmid-volatile met coal. The total cost of the project is expected to be approximately $53 million of which approximately $22 million was incurred in 2011.Production from the Amonate Complex is expccted to begin in 2012.Construction of a new slope and overland belt at the Enlow Fork Mine in Pennsylvania began in 2010 and is expected to be completed by the end of2013. Overland belt projects are expected to enhance safety, improve productivity, increase production and reduce costs. Modern conveyor systems typicallyprovide high availability rates, thereby allowing mining equipment to produce at higher levels. Overland belts do not require the daily maintenance of the mineroof that underground haulage systems require allowing manpower to be reduced or redeployed to more productive work. Mine safety is expected to beenhanced by overland belts because older underground belt areas will be sealed. The total cost of the project is expected to be approximately $207 million ofwhich approximately $28 million was incurred in 2011. As of December 31, 2011, total project-to-date expenditures were approximately $38 million.Also, in accordance with a consent decree with the U.S Environmental Protection Agency and the West Virginia Environmental Protection Agency,CONSOL Energy began construction of an advance water processing system (RO) in Northern West Virginia in 2011. The RO will provide a treatmentsystem for the mine water generated from the Robinson Run, Loveridge, and Blacksville #2 Mines to be in compliance with the existing National PollutionDischarge Elimination System (NPDES) permits. Construction was started in April 2011 and final commissioning of the RO system is expected to becomplete by the end of May 2013. Expenditures related to the Northern West Virginia plant of $48.0 million were incurred in 2011 and total costs related to theconstruction of this plant and related facilities is expected to be approximately $200 million. 2011 2012 Actual Capital Forecasted Capital Expenditures ExpendituresCoal (in millions) Maintenance of Production $243 $277 Efficiency Projects (e.g., overland belts) $183 $146 Increases in Production (e.g., BMX) $114 $203 Safety $18 $50Total Coal $558 $67618Coal Marketing and SalesOur sales of bituminous coal were at average sales price per ton sold as follows: Years Ended December 31, 2011 2010 2009Average Sales Price Per Ton Sold– Thermal Coal $58.87 $53.76 $56.64Average Sales Price Per Ton Sold– High Volatile Met Coal $78.06 $72.89 $—Average Sales Price Per Ton Sold– Low Volatile Met Coal $191.81 $146.32 $107.72Average Sales Price Per Ton Sold– Total Company $72.25 $61.33 $58.70We sell coal produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United Statessales offices in Charlotte, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies.A breakdown of total coal sales, including our portion of equity affiliates, are as follows: Tons Percent of Sold TotalThermal 53.4 83%High Volatile Metallurgical 4.8 8%Low Volatile Metallurgical 5.6 9% Total tons sold 63.8 100%Approximately 75% of our 2011 coal sales were made to U. S. electric generators,18% of our 2011 coal sales were priced on export markets and 7% ofour coal sales were made to other domestic customers. We had approximately 105 customers in 2011. During 2011, one customer individually accounted formore than 10% of total revenue, and the top four coal customers accounted for more than 30% of our total revenues.Coal ContractsWe sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding process.Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average contract term is between one to three years.However, several multi-year agreements have terms ranging from five to twenty years. As a normal course of business, efforts are made to renew or extendcontracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past. For the yearended December 31, 2011, over 84% of all the coal we produced was sold under contracts with terms of one year or more.19The following table sets forth as of January 26, 2012, CONSOL Energy's estimated production and sales for 2012 through 2014.COAL DIVISION GUIDANCE(Tons in millions) 1Q 2012 2012 2013 2014Estimated Coal Production 15.5-15.9 59.5-61.5 60.5-62.5 64.5-66.5 Estimated Low-Vol Met Sales 1.0 4.5-5.0 4.5-5.0 4.5-5.0 Tonnage - Firm 1.0 1.9 0.1 — Average Price - Sold (firm) $189.68 $185.66 $93.48 N/A Price - Estimated (for open tonnage) $115-$145 $120-$150 N/A N/A Estimated High-Vol Met Sales 1.0 5.0 5.0 5.5-6.0 Tonnage - Firm 0.7 1.9 0.2 0.1 Average Price - Sold (firm) $84.47 $82.10 $90.27 $105.58 Price - Estimated (for open tonnage) $68-$75 $68-$80 N/A N/A Estimated Thermal Sales 13.2 49.6-51.1 50.4-51.9 53.9-54.9 Tonnage - Firm 12.5 49.7 23.5 14.4 Average Price - Sold (firm) $61.64 $62.77 $62.77 $64.01 Price - Estimated (for open tonnage) $58-$65 $58-$65 N/A N/ANote: N/A means not available or not forecasted. In the thermal sales category, the firm tonnage does not include 4.7 million collared tons in 2013, with a ceiling of$59.78 per ton and a floor of $51.63 per ton or 7.0 million collared tons in 2014, with a ceiling of $60.13 per ton and a floor of $46.76 per ton. Total estimated coalsales for 2012, 2013 and 2014 include 0.4, 0.6 and 0.6 million tons, respectively, from Amonate. The Amonate tons are not included in the category breakdowns.None of the Amonate tons have been sold.Coal pricing for contracts with terms of one year or less is generally fixed. Coal pricing for multiple-year agreements generally provides the opportunityto periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:•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.The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated,the parties may vary the timing of the deliveries within specified limits.Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events.Force majeure events include, but are not limited to, labor disputes and unexpected significant geological conditions. Depending on the language of the contract,some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.DistributionCoal is transported from CONSOL Energy's mining complexes to customers by means of railroad cars, river barges, trucks, conveyor belts or acombination of these means of transportation. We employ transportation specialists who negotiate freight and equipment agreements with varioustransportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for certain customers. Mostcustomers negotiate their own freight contracts.At December 31, 2011 we operated 22 towboats, 5 harbor boats and a fleet of approximately 625 barges that serve customers along the Ohio, Allegheny,Kanawha and Monongahela Rivers. The barge operation allows us to control delivery schedules and has served as temporary floating storage for coal whenland storage is unavailable.20DETAIL GAS OPERATIONSOur Gas operations are located throughout Appalachia. While CBM remains our largest share of production much of our future growth will likely comefrom the development of our Marcellus Shale play and the exploration of our Utica Shale play.Coalbed Methane (CBM)We have the rights to extract CBM in Virginia from approximately 359,000 net CBM acres, which cover a portion of our coal reserves in CentralAppalachia. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by our Buchanan Mine. This seam is generallyfound at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas perton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively,this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to core hole data that allows us to determine the amount of coalpresent, the geologic structure of the coal seam and the gas content of the coal.We also have the right to extract CBM in northwestern West Virginia and southwestern Pennsylvania from approximately 859,000 net CBM acres,which contain most of our recoverable coal reserves in Northern Appalachia. We produce gas primarily from the Pittsburgh #8 coal seam. This seam isgenerally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh #8 seam. Collectively, this series of coal seamsrepresents a total thickness ranging from 10 to 30 feet. We have access to information that allows us to determine the amount of coal present, the geologicstructure of the coal seam and the gas content of the coal.In central Pennsylvania we have the right to extract CBM from approximately 263,000 net CBM acres, which contain most of our recoverable coalreserves as well as significant leases from other coal owners. In addition, we control 810,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee.We also have the right to extract CBM on 139,000 net acres in the San Juan Basin, 92,000 net acres in eastern Ohio and central West Virginia, and 20,000 netacres in the Powder River Basin.Marcellus ShaleWe have the rights to extract natural gas in Pennsylvania, West Virginia and New York from approximately 361,000 net Marcellus acres at December31, 2011. In September 2011, CONSOL Energy entered into a joint venture with Noble Energy regarding our Marcellus Shale oil and gas assets andproperties in West Virginia and Pennsylvania. The joint venture holds approximately 628,000 net Marcellus Shale acres in those states as well as theproducing Marcellus Shale Wells which we had owned. We hold a 50% interest in the joint venture. We also hold a 50% interest in a related gathering companyto which we contributed our existing Marcellus Shale gathering assets. Joint operations are conducted in accordance with a joint development agreement.CONSOL Energy's Marcellus wells are primarily horizontal wells with 2,500 to 5,000 feet of lateral length. The longer lateral lengths allow forproportionately higher gas production from a single well compared to shorter length lateral wells.CONSOL Energy continues to develop its Marcellus assets.Utica ShaleCONSOL Energy also controls approximately 114,000 net acres of Utica Shale potential in southeastern Ohio, southwestern Pennsylvania, and northernWest Virginia at December 31, 2011. Additionally, CONSOL Energy controls a large number of acres that contain the rights to the Utica Shale but aredisclosed in other plays due to the Utica Shale not being the primary drilling target as of December 31, 2011. The thickness of the Utica Shale in this arearanges from 200 to 450 feet. Further delineation of the Ohio acreage potential exploration play is planned for 2012.To facilitate the delineation in Ohio, CONSOL Energy entered into a joint venture with Hess Ohio Developments, LLC (Hess) in the fourth quarter of2011. The Hess joint venture owns approximately 200,000 net acres of Utica Shale rights in Ohio. We hold a 50% interest in the joint venture. Joint operationsare conducted in accordance with a joint development agreement.21Shallow Oil and GasThe shallow oil and gas acreage position of CONSOL Energy is approximately 518,000 net acres mainly in West Virginia, Pennsylvania, Virginia, NewYork, San Juan Basin and Powder River Basin at December 31, 2011. The majority of our shallow oil and gas leasehold position is held by production andall of it is extensively overlain by existing third party gas gathering and transmission infrastructure. The shallow oil and gas assets provide multiple synergieswith our CBM and unconventional shale operations, and the held by production nature of the shallow oil and gas properties affords CONSOL Energyconsiderable flexibility to choose when to exploit those and other gas assets including shale assets.Other GasWe control approximately 346,000 net acres of rights to gas in the New Albany shale in Kentucky, Illinois, and Indiana. The New Albany shale is aformation containing gaseous hydrocarbons, and our acreage position has thickness of 50-300 feet at an average depth of 2,500-4,000 feet. The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth of approximately 3,500 feet. The shale thickness is between 40-80 feet,and CONSOL Energy has found it to be rich in total organic content. CONSOL Energy has 249,000 net acres of Chattanooga Shale. This largely contiguousacreage is composed of only a small number of leases, a rarity in Appalachia. CONSOL Energy is the operator of all of its Chattanooga Shale wells.We have 457,000 net acres of Huron shale potential in Kentucky, West Virgina, and Virginia; a portion of this acreage has tight sands potential.Summary of Properties as of December 31, 2011 Shallow Oil CBM and Gas Marcellus Other Gas Segment Segment Segment Segment TotalEstimated Net Proved Reserves (million cubic feetequivalent) 1,729,571 740,165 881,881 128,410 3,480,027Percent Developed 68% 91% 27% 29% 61%Net Producing Wells (including gob wells) 4,231 8,351 58 85 12,725Net Proved Developed Acres 247,192 166,255 1,690 6,737 421,874Net Proved Undeveloped Acres 72,819 34,363 5,101 11,993 124,276Net Unproved Acres(1) 2,221,532 316,902 354,347 1,147,817 4,040,598 Total Net Acres(2) 2,541,543 517,520 361,138 1,166,547 4,586,748____________(1)Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required aswe further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that ourassumptions 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 gasseams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect theacre in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.22Producing Wells and AcreageMost of our development wells and proved acreage is located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term,but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The followingtable sets forth, at December 31, 2011, the number of producing wells, developed acreage and undeveloped acreage: Gross Net(1)Producing Wells (including gob wells) 14,743 12,725Proved Developed Acreage 507,949 421,874Proved Undeveloped Acreage 146,479 124,276Unproven Acreage 5,035,749 4,040,598 Total Acreage 5,690,177 4,586,748___________(1)Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be requiredas we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that ourassumptions and methodology in this regard are reasonable.Development Wells (Net)During the years ended December 31, 2011, 2010 and 2009 we drilled 254.9, 317.0 and 247.0 net development wells, respectively. Gob wells and wellsdrilled by other operators that we participate in are excluded. There were no dry development wells in 2011, one dry development well in 2010, and one drydevelopmental well in 2009. As of December 31, 2011, forty-seven net developmental wells are still in process. The following table illustrates the net wellsdrilled by well classification type: For the Year Ended December 31, 2011 2010 2009CBM segment 221.4 184.0 228.0Shallow Oil and Gas segment 4.0 107.0 5.0Marcellus segment 17.5 24.0 14.0Other Gas segment 12.0 2.0 — Total Development Wells 254.9 317.0 247.0 For the year ended December 31, 2011, the Marcellus Segment includes 15 gross developmental wells drilled prior to September 30, 2011. A 50%interest in these wells was subsequently sold to Noble on September 30, 2011. Net developmental wells of 2.5 were drilled after September 30, 2011 under thejoint venture agreement and are reflected in the table above at the applicable ownership percentage.23Exploratory Wells (Net)During the years ended December 31, 2011, 2010 and 2009, we drilled in the aggregate 69.5, 38 and 18 net exploratory wells, respectively. As ofDecember 31, 2011, 2.5 net exploratory wells are still in process. The following table illustrates the exploratory wells drilled by well classification type: For the Year Ended December 31, 2011 2010 2009 Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval.CBM segment — — — — — — 2.0 — —Shallow Oil and Gas segment 12.0 1.0 1.0 2.0 — 3.0 2.0 — 2.0Marcellus segment 47.5 1.0 — — — — 2.0 1.0 —Other Gas segment 5.5 — 1.5 18.0 2.0 13.0 5.0 — 4.0 Total 65.0 2.0 2.5 20.0 2.0 16.0 11.0 1.0 6.0For the year ended December 31, 2011, the Marcellus Segment includes 41 gross exploratory wells drilled prior to September 30, 2011. A 50%interest in these wells was sold to Noble on September 30, 2011. Net exploratory wells of 7.5 were drilled after September 30, 2011 under the joint ventureagreement and are reflected in the table above at the applicable ownership percentage.ReservesThe following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proveddeveloped and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods andgovernment regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC). CONSOL Energyhas not filed reserve estimates with any federal agency. Net Reserves (Million cubic feet equivalent) as of December 31, 2011 2010 2009Proved developed reserves 2,135,805 1,931,272 1,040,257Proved undeveloped reserves 1,344,222 1,800,325 871,134Total proved developed and undeveloped reserves(a) 3,480,027 3,731,597 1,911,391___________(a)For additional information on our reserves, see “Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated FinancialStatements in Item 8 of this Form 10-K.24Discounted Future Net Cash FlowsThe following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%: Discounted Future Net Cash Flows (Dollars in millions) 2011 2010 2009Future net cash flows $4,877 $5,474 $2,391Total PV-10 measure of pre-tax discounted future net cash flows (1) $2,861 $2,780 $1,480Total standardized measure of after tax discounted future net cash flows $1,747 $1,661 $894____________(1)We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-GenerallyAccepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professionalanalysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact theamount 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 nota measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure asdefined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.Reconciliation of PV-10 to Standardized Measure As of December 31, 2011 2010 2009 (Dollars in millions)Future cash inflows $14,804 $16,724 $7,975Future production costs (5,263) (5,176) (3,123)Future development costs (including abandonments) (1,675) (2,720) (996)Future net cash flows (pre-tax) 7,866 8,828 3,85610% discount factor (5,006) (6,048) (2,376)PV-10 (Non-GAAP measure) 2,860 2,780 1,480Undiscounted income taxes (2,989) (3,354) (1,465)10% discount factor 1,876 2,235 879Discounted income taxes (1,113) (1,119) (586)Standardized GAAP measure $1,747 $1,661 $89425Gas ProductionThe following table sets forth net sales volumes produced for the periods indicated: For the Year Ended December 31, 2011 2010 2009 (in million cubic feet)CBM segment 92,360 91,351 86,944Shallow Oil and Gas segment 32,168 24,646 1,663Marcellus segment 26,873 10,408 4,950Other Gas segment 2,103 1,470 858 Total Produced 153,504 127,875 94,415Gas Capital ProjectsCONSOL Energy plans to spend $473 million on developing its extensive Marcellus Shale assets in 2012. Included in this is drilling capital of $333million. The budget anticipates that the CONSOL/Noble Energy joint venture will drill 99 (gross) horizontal Marcellus Shale wells, including 39 (gross)wells in the liquids-rich area of the play. CONSOL also expects to invest $77 million in related gathering and compression and $63 million on other relateditems.In the CONSOL/Hess joint venture in the Utica Shale, CONSOL Energy expects to invest $53 million in 2012. Most of that will be drilling capital forCONSOL Energy's share of up to 22 gross wells. Most of the Utica drilling is expected to occur in either the liquids-rich area or the oil window of the play.As a result, the total drilling in the liquids-rich/oil window is expected to be the 39 (gross) wells in the Marcellus Shale, plus the 22 (gross) wells in theUtica Shale, for a total of 61 (gross) wells out of the 121 (gross) wells, or 50%, expected to be drilled in the two plays.The CBM program will be scaled back in 2012 with the expected drilling of only 86 wells. Total capital for the 2012 CBM program is estimated to be$65 million.Across all of the gas plays, the $623 million includes $433 million of drilling capital, $108 million of gathering and compression capital, $21 millionfor production equipment, $23 million for water, $23 million for land and $15 million for other.As a result of the expected gas investment, CONSOL Energy projects its 2012 gas production to be 160 Bcfe net to CONSOL Energy. This will be anincrease of nearly 12%, off of pro forma 2011 production of 142.9 Bcf, adjusted for the partial year impact of Marcellus assets sold to Noble Energy andAntero Resources.The company expects 2013 gas/liquids production target of between 190 - 210 Bcfe, which will be achieved largely from the ramp-up in drilling in2012.The table below summarizes the 2011 actual expenditures made for gas and the forecasted expenditures for 2012. 2011 2012 Actual Capital Forecasted Capital Expenditures ExpendituresGas (in millions) Marcellus Shale $427 $473 Utica Shale $3 $53 CBM $130 $65 Other $102 $32Total Gas $662 $62326Gas SalesAverage Sales Price and Average Lifting CostThe following table sets forth the total average sales price and the total average lifting cost for all of our gas production for the periods indicated,including intersegment transactions. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion oramortization. See Part II Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K for a breakdownby segment. For the Year Ended December 31, 2011 2010 2009Average Gas Sales Price Before Effects of Financial Settlements (per thousand cubic feet) $4.27 $4.53 $4.15Average Effects of Financial Settlements (per thousand cubic feet) $0.63 $1.30 $2.53Average Gas Sales Price Including Effects of Financial Settlements (per thousand cubic feet) $4.90 $5.83 $6.68Average Lifting Costs excluding ad valorem and severance taxes (per thousand cubic feet) $0.68 $0.50 $0.48We enter into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed tobe sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance issues or a weather related force majeure event,we have not failed to deliver quantities required under contract. We also enter into various gas swap transactions that qualify as financial cash flow hedges.These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 84.0 billion cubic feet of our produced gassales volumes for the year ended December 31, 2011 at an average price of $5.21 per thousand cubic feet. These financial hedges represented approximately52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet. As ofDecember 31, 2011, we expect these transactions will cover approximately 76.9 billion cubic feet of our estimated 2012 production at an average price of$5.25 per thousand cubic feet, 50.8 billion cubic feet of our estimated 2013 production at an average price of $5.06 per thousand cubic feet, 44.0 billioncubic feet of our estimated 2014 production at an average price of $5.20 per thousand cubic feet and 3.8 billion cubic feet of our estimated 2015 production atan average price of $3.97 per thousand cubic feet.We have purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2011, wehave secured firm transportation capacity to cover more than our 2012, 2013 and 2014 hedged production.The hedging strategy and information regarding derivative instruments used are outlined in Part II Item 7A Qualitative and Quantitative DisclosuresAbout Market Risk and in Note 23 – Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.Midstream Gas ServicesCONSOL Energy has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines orother local sales points. In addition, CONSOL Energy acquired extensive gathering assets in the Dominion Acquisition in 2010. CONSOL Energy now ownsor operates approximately 4,000 miles of gas gathering pipelines as well as 230,000 horsepower of compression, of which, approximately 80% is wholly ownedwith the balance being leased. Along with this compression capacity, CONSOL Energy owns and operates a number of gas processing facilities. Thisinfrastructure is capable of delivering 200 billion cubic feet per year of pipeline quality gas.On September 30, 2011, in connection with the Noble joint venture for Marcellus wells and leaseholdings, CONE Gathering, LLC was formed.CONSOL Energy and Noble each own 50% of CONE Gathering. CONE Gathering was formed to develop, operate and own both Noble's and CONSOLEnergy's Marcellus gathering system needs.Upon formation of CONE Gathering, CONSOL Energy contributed its then existing Marcellus Shale gathering assets to CONE Gathering. We believethat the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONEGathering a tremendous advantage in building the midstream assets required to develop the joint venture's Marcellus position.CONSOL Energy has had the advantage of having gas production from CBM, which can be lower Btu than pipeline27specification, as well as higher Btu Marcellus production which can complement each other by reducing and in some cases eliminating the need for the costlyprocessing of CBM. In addition, the lower Btu CBM production offers an opportunity to blend ethane back into the gas stream when pricing or capacity forethane markets dictate. This will allow CONSOL Energy more flexibility in bringing Marcellus on-line at qualities that meet interstate pipeline specifications.Other OperationsCONSOL Energy provides other services both to our own operations and to others. These include land services, industrial supply services, terminalservices (including break bulk, general cargo and warehouse services), river and dock services and water services.Non-Core Mineral Assets and Surface PropertiesCONSOL Energy owns significant coal and gas assets that are not in our short or medium term development plans. We continually explore themonetization of these non-core assets by means of sale, lease, contribution to joint ventures, or a combination of the foregoing in order to bring the value ofthese assets forward for the benefit of our shareholders. We also control a significant amount of surface acreage. This surface acreage is valuable to us in thedevelopment of the gathering system for our Marcellus Shale and Utica Shale production. We also derive value from this surface control by granting rights ofway or development rights to third parties when we are able to derive appropriate value for our shareholders.Industrial Supply ServicesFairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining, drilling, and industrial supplies in the UnitedStates. Fairmont Supply has 37 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services.Integrated supply procurement is a materials management strategy that utilizes a single, full-line distribution to minimize total cost in the maintenance, repairand operating supply chain.Fairmont Supply provides mine and drilling supplies to CONSOL Energy's mining and gas operations. Approximately 45% of Fairmont Supply's salesin 2011 were made to CONSOL Energy's coal and gas divisions.Terminal ServicesIn 2011, approximately 12.6 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminal Inc.'s, exportingterminal in the Port of Baltimore. Approximately 48% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coalor load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern Corporationand CSX Transportation Inc. River and Dock ServicesCONSOL Energy's river operations, located in Monessen, Pennsylvania, transport coal from our mines, coal from other mines and non-coalcommodities from river loadout facilities located primarily along the Monongahela and Ohio Rivers in northern West Virginia and southwestern Pennsylvania.Products are delivered to customers along the Monongahela, Ohio, Kanawha and Allegheny rivers. At December 31, 2011, we operated 22 towboats, 5 harborboats and approximately 625 barges. In 2011, our river vessels transported a total of 19.1 million tons of coal and other commodities, including 6.2 milliontons of coal produced by CONSOL Energy mines.CONSOL Energy provides dock services for our mines as well as for third parties at our Alicia Dock, located on the Monongahela River in FayetteCounty, Pennsylvania. CONSOL Energy transfers coal from rail cars to barges for customers that receive coal on the river system.Water ServicesCNX Water Assets LLC, a CONSOL Energy subsidiary, is acquiring and developing existing sources of water used to support our coal and gasoperations. CNX Water Assets LLC, operates an advanced waste water treatment plant in support of coal operations as well as fresh water reservoirs. CNXWater Assets objective is to develop and maximize the value of existing water assets, which will be used to provide water for drilling and hydraulic fracturingin support of gas operations and meeting the needs of mining operations. CNX Water also has contracts to provide water to third parties for industrial usefrom various water sources owned by CONSOL Energy. 28Employee and Labor RelationsAt December 31, 2011, CONSOL Energy had 9,157 employees, approximately 32% of whom were represented by the United Mine Workers ofAmerica (UMWA). In 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a newcollective bargaining agreement which will run from July 1, 2011 to December 31, 2016. The National Bituminous Coal Wage Agreement of 2011 (2011NBCWA) covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement to the 2007 NBCWA thatwas 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 hourcontribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWArepresented 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 havethe 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 in2014, 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 definedcontribution 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.Laws and RegulationsThe mining and gas industries are subject to regulation by federal, state and local authorities on matters such as the discharge of materials into theenvironment, permitting and other licensing requirements, reclamation and restoration of properties after mining or gas operations are completed, managementof materials generated by mining and gas operations, pipeline compression and transmission of natural gas and liquids, surface subsidence from undergroundmining, water discharge effluent limits, water appropriation, air quality standards, protection of wetlands, endangered plant and wildlife protection,limitations on land use, storage of petroleum products and substances that are regarded as hazardous under applicable laws, management of electricalequipment containing polychlorinated biphenyls (PCBs), legislatively mandated benefits for current and retired coal miners, and employee health and safety.In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, whichcould affect demand for CONSOL Energy's coal and gas products. The possibility exists that new legislation or regulations may be adopted which wouldhave a significant impact on CONSOL Energy's mining or gas operations or our customers' ability to use coal or gas and may require CONSOL Energy orour customers to change their operations significantly or incur substantial costs.Numerous governmental permits and approvals are required for mining and gas operations. Regulations provide that a mining permit or modificationcan be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position tocontrol another entity that has outstanding permit violations. Thus, all mining operations of CONSOL Energy entities must be maintained in compliance toavoid delay in issuance of necessary mining permits. CONSOL Energy is, or may be, required to prepare and present to federal, state or local authorities dataand/or analysis pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment, the public andemployee health and safety. Permits we need may include requirements that may be subject to future restrictive standards or interpreted in a manner whichrestricts our ability to conduct our mining and gas operations or to do so profitably. Future legislation and administrative regulations may increasinglyemphasize the protection of the environment and employee health and safety. As a consequence, the activities of CONSOL Energy may be more closelyregulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operatingcosts to CONSOL Energy and delays, interruptions or a termination of operations, the extent of which cannot be predicted.Compliance with these laws has substantially increased the cost of mining and gas production for all domestic coal and gas producers. We post suretyperformance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, oftenincluding the cost of treating mine water discharge. We also post29performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. Weendeavor to conduct our mining and gas operations in compliance with all applicable federal, state and local laws and regulations. However, because ofextensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions, permit exceedances and violationsduring mining and gas production can and do occur. CONSOL Energy made capital expenditures for environmental control facilities of approximately $53.1million, $39.9 million and $50.4 million in the years ended December 31, 2011, 2010 and 2009, respectively. The capital expenditures for environmentalcontrol facilities in 2009 were primarily related to starting construction of an advanced water processing system at the Buchanan Mine. Construction of thisfacility was completed in 2010. In accordance with a consent decree with the U.S. Environmental Protection Agency and the West Virginia EnvironmentalProtection Agency, CONSOL Energy began construction of an advance water processing system in Northern West Virginia in 2011. Construction is expectedto be complete in 2013. Expenditures related to the Northern West Virginia plant of $48.0 million were incurred in 2011 and total costs related to theconstruction of this plant and related facilities is expected to be approximately $200 million. CONSOL Energy expects to have capital expenditures of $132.2million in 2012 for environmental control facilities. Mine Health and Safety LawsLegislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, andengage in additional training. We have also experienced more aggressive inspection protocols resulting in the issuance of more citations and with newregulations the amount of civil penalties have increased.The actions taken thus far by federal and state governments include requiring:•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 evacuationfrom 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.On August 31, 2011, MSHA published a proposed rule, which if adopted, would require proximity protection for miners. The proposed rule wouldrequire certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoidinjuries where individuals could be caught between equipment and blocks of unmined coal. MSHA is also considering new rules to reduce the permissibleconcentration of respirable dust in underground coal mines. This rule, if adopted, would reduce the current standard of two milligrams per cubic meter of airto some lower amount.Occupational Safety and Health ActOur gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) and comparable state laws in some states, allof which regulate health and safety of employees at our gas operations. Also, OSHA's hazardous communication standard requires that information bemaintained about hazardous materials used or produced by our gas operations and that this information be provided to employees, state and local governmentsand the public.Black Lung LegislationUnder federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:•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 noresponsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where theresponsible 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 upto $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.The Patient Protection and Affordable Care Act (PPACA), which was implemented in 2010, made two changes to the Federal Black Lung BenefitsAct. First, it provided changes to the legal criteria used to assess and award claims by creating a legal30presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from atotally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was notcaused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passes away,regardless of the cause of the miner's death. In addition to the federal legislation, we are also liable under various state statutes for black lung claims.Retiree Health Benefits LegislationThe Coal Industry Retiree Health Benefit Act of 1992 (the Act) established the Combined Benefit Fund (the Combined Fund). The Combined Fundprovides medical and death benefits for all beneficiaries including orphan retirees of the former United Mine Workers of America (UMWA) Benefit Trustswho were actually receiving benefits as of July 20, 1992. The Act also created a second benefit fund for UMWA retirees, the 1992 Benefit Plan. The 1992Benefit Plan principally provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and whoactually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former signatory employers or relatedcompanies and the allocation of responsibility for unassigned beneficiaries (referred to as orphans) to the assigned operators. The task of calculating theannual per beneficiary premium that assigned operators are obligated to pay to the Combined Fund is the responsibility of the Commissioner of SocialSecurity.The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the National Bituminous Coal WageAgreement (NBCWA) of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the1992 Benefit Fund, or whose last employer signed the 1993 NBCWA or a later NBCWA, and who subsequently goes out of business.The Act requires some of our signatory subsidiaries to make premium payments to the Combined Fund and to the 1992 Benefit Plan for the cost of ourretirees and orphan retirees in those plans. In addition, the NBCWA of 2011 requires our signatory subsidiaries to make specified payments to the 1993Benefit Plan through 2016. The Tax Relief and Health Care Act of 2006 (the 2006 Act) provides additional federal funding for these orphan costs byauthorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land (AML) trust fund. The additional federal funding,depending upon its magnitude and the amount of orphan benefits payable, should cover the orphan premium payments due under the Combined Fund as wellas the orphan premium payments due under the 1992 Benefit Plan. Federal contributions were 100% in 2011 and are expected to continue to be 100% after2011. In addition, federal contributions cover the costs for those orphan retirees as of December 31, 2006 under the 1993 Benefit Plan. Under the 2006 Act,these general fund contributions to the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit Plan and certain AML payments to the states and Indiantribes are collectively limited by an aggregate annual cap of $490 million. These federal contributions do not apply to our subsidiaries' assigned retired miners,and therefore our subsidiaries will continue to make premium payments for our assigned retired miners who receive benefits from the Combined Fund, the1992 Benefit Plan and for certain beneficiaries of the 1993 Benefit Plan. In addition, our subsidiaries remain responsible for making orphan premiumpayments to the Combined Fund and 1992 Benefit Plan to the extent that the federal contributions are not sufficient to cover the benefits.Pension Protection ActThe Pension Protection Act of 2006 (the Pension Act) has simplified and transformed rules governing the funding of defined benefit plans, acceleratedfunding obligations of employers, made permanent certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 (EGTRRA), madepermanent the diversification rights and investment education provisions for plan participants and encourages automatic enrollment in defined contribution401(k) plans. In general, most provisions of the Pension Act of 2006 are in effect for plan years beginning on or after December 31, 2008. Plans generally arerequired to set a funding target of 100% of the present value of accrued benefits and sponsors are required to amortize unfunded liabilities over a seven yearperiod. The Pension Act includes a funding target of 100% after 2010. Plans with a funded ratio of less than 80%, or less than 70% using specialassumptions, will be deemed to be "at risk" and will be subject to additional funding requirements. The 2011 plan year funding ratio of CONSOL Energy'ssalary retirement plan was 100%. The funding ratio is subject to year over year volatility and Internal Revenue Service's calculation guidelines.31Environmental LawsCONSOL Energy is subject to various federal environmental laws, including:•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,as administered and enforced by the United States Environmental Protection Agency (EPA) and/or authorized federal or state agencies, as well as statelaws of similar scope, and other state environmental and conservation laws in each state in which CONSOL Energy operates.These environmental laws require reporting, permitting and/or approval of many aspects of coal mining and gas operations. Both federal and stateinspectors regularly visit mines and other facilities to ensure compliance. CONSOL Energy has ongoing compliance and permitting programs designed toensure compliance with such environmental laws.Given the retroactive nature of certain environmental laws, CONSOL Energy has incurred, and may in the future incur liabilities in connection withproperties and facilities currently or previously owned or operated. These liabilities may be increased to include sites to which CONSOL Energy or oursubsidiaries sent waste materials. Surface Mining Control and Reclamation ActThe Surface Mining Control and Reclamation Act (SMCRA) establishes minimum national operational, reclamation and closure standards for allsurface mines as well as most aspects of deep mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met duringthe course of and following completion of mining activities. Permits for all mining operations must be obtained from the Office of Surface Mining (OSM) or,where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operatefederally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM's regulations and in manyinstances have done so. All states in which CONSOL Energy's active mining operations are located have achieved primary jurisdiction for enforcement ofSMCRA through approved state programs.SMCRA permit provisions include requirements for coal exploration; baseline environmental data collection and analysis; mine plan development;topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance;subsidence control for underground mines; refuse disposal plans; surface drainage control; mine drainage and mine discharge control and treatment; and sitereclamation. All states also impose an obligation on surface mining operations to restore or replace domestic, agricultural or industrial water supplies and onunderground mine operations to restore or replace drinking, domestic or residential water supplies adversely affected by such operations. In addition, SMCRAimposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (AML Fund),which is used to restore unreclaimed and abandoned mine lands mined before 1977. The current per ton fee is $0.315 per ton for surface mined coal and$0.135 per ton for underground mined coal. From October 1, 2012 through September 30, 2021, the fees will be $0.28 per ton for surface mined coal and$0.12 per ton for underground mined coal.OSM is currently considering modifications to the existing stream buffer zone regulation, which amendments are referred to as the Stream ProtectionRule. An advanced notice of proposed rulemaking (ANPR) was published in November 2009. Based on the ANPR, the proposed rule would apply to surfacemining as well as underground mining activities that may impact streams. Although it is too early to predict what the impacts of the proposed amendmentswill be, all of the alternatives identified in the ANPR could result in loss of access to significant amounts of coal and/or significant increases in reclamationcosts. In Pennsylvania, where CONSOL Energy operates two longwall mines, approximately $29.4 million, $21.8 million and $30.3 million of expenses wereincurred during the years ended December 31, 2011, 2010 and 2009, respectively, to mitigate and repair impacts on streams from subsidence. With respect tosubsidence impacts to streams, the regulatory requirement to minimize impacts to the hydrologic balance could cause CONSOL Energy to change mine plans,to incur significant costs, and potentially even shut down mines in order to meet compliance requirements. We currently estimate expenses related tosubsidence of streams in Pennsylvania will be approximately $34.7 million for the year ended December 31, 2012.32Clean Air Act and Related RegulationsThe federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect coal mining, coal handling and processing,and gas production and processing operations primarily through permitting and/or emissions control requirements.The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of the coal fired electric power generatingplants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coalis burned. Carbon dioxide, a greenhouse gas, is also emitted when coal is burned. Environmental regulations governing emissions from coal-fired electricgenerating plants could affect demand for coal as a fuel source and affect the volume of our sales.In 2011, the EPA promulgated or finalized several rulemakings impacting coal generating facilities. These include the Cross-State Air Pollution Rule toregulate sulfur dioxide (SO2), nitrogen dioxide (NOx) and fine particulate matter; and the Utility Maximum Achievable Control Technology (Utility MACT)rule which sets new mercury and air toxic standards and includes more stringent new source performance standards (NSPS) for particulate matter (PM), SO2and NOX.In addition, the EPA is proposing to establish NSPS for Green House Gas (GHG) emissions from new electric generating units and proposed regulationsto establish GHG emission limits for new and modified electric generating units. The EPA anticipates that a notice of proposed rulemaking (NOPR) will bepublished in the Federal Register in early 2012. Such regulations could significantly increase the cost of generation of electricity at coal fired facilities andcould make competing forms of electricity generation more competitive.The Clean Air Act and comparable state laws restrict the emission of air pollutants from compressor stations and other equipment and facilities used inour gas operations. We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or touse specific equipment, technologies or best management practices to control emissions. In August 2011, the EPA published proposed revisions to the NSPSand proposed revisions to the national emission standards for hazardous air pollutants (NESHAPS) for the Oil and Natural Gas Sector. The EPA intends toissue the final revisions in early 2012. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of thisrule requires reporting of emissions from coal mines and gas wells and associated facilities for 2011 emissions.Clean Water ActThe federal Clean Water Act (CWA) and corresponding state laws affect coal and gas operations by regulating discharges into surface waters. Permitsrequiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. TheClean Water Act and corresponding state laws include requirements for: improvement of designated "impaired waters" (not meeting state water qualitystandards) through the use of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use" streams byrestricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, seleniumand dissolved solids; for minimizing impacts and compensating for unavoidable impacts resulting from discharges of fill materials to regulated streams andwetlands; and the requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition, the Spill Prevention,Control and Countermeasure (SPCC) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids, including brine and oil,and require that plans be in place to address any spills and that secondary containment be installed around all tanks. These requirements may causeCONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.In order to obtain a permit for surface coal mining activities, including valley fills associated with steep slope mining, an operator must obtain a permitfor the discharge of fill material from the Army Corps of Engineers (the COE) pursuant to Section 404 of the Clean Water Act and must obtain a dischargepermit from the state regulatory authority under the state counterpart to Section 402 of the Clean Water Act authorizing the issuance of national pollutantdischarge elimination permits or NPDES permits. Beginning in early 2009, the EPA took a number of initiatives that have resulted in delays and obstructionof the issuance of such permits for surface mining operation in the states of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia (designatedas "Appalachian Surface Coal Mining"). Increased oversight of delegated state programmatic authority, coupled with individual permit review and additionalrequirements imposed by the EPA, has resulted in delays in the review and issuance of permits for surface coal mining operations, including applications forsurface facilities for underground mines, such as applications for coal refuse disposal areas. Thus far, CONSOL Energy subsidiaries have been able tocontinue operating their existing mines. However, such delays and obstructions in the permitting process may cause CONSOL Energy33to incur additional costs that could adversely affect our operating results, financial condition and cash flows.Pursuant to a Congressional requirement in the EPA's 2010 budget appropriation, the EPA must conduct a comprehensive study of the potential adverseimpact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formationssuch as the Barnett and Marcellus shales. The EPA initiated the study in early January 2011 and plans to make the initial study results available by late2012, with a final report to Congress soon thereafter. The EPA has also announced plans to conduct a review of water produced in conjunction with theproduction of Coal Bed Methane (CBM) to determine whether its disposal should be further regulated.Endangered Species ActThe Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered and threatenedspecies may cause us to modify mining plans, gas well pad siting or pipeline right of ways, or develop and implement species-specific protection andenhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate areprotected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe thatthere are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal or produce gas from ourproperties.Comprehensive Environmental Response, Compensation and Liability Act (Superfund)The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state laws create liabilities for the investigationand remediation of releases of hazardous substances into the environment and for damages to natural resources. We could incur liability under CERCLArelative to our coal or gas operations. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with theinvestigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and othermatters under Superfund and similar state environmental laws. We also must comply with reporting requirements under the Emergency Planning andCommunity Right-to-Know Act and the Toxic Substances Control Act.From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to sites that have released hazardoussubstances. We have been in the past and currently are named as a potentially responsible party at Superfund sites. We may become involved in futureproceedings, litigation or investigations and incur liabilities that could be materially adverse to us.Resource Conservation and Recovery ActThe federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect coal mining and gas operations byimposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposedare subject to corrective action orders issued by the EPA which could adversely affect our results, financial condition and cash flows.The EPA is currently reconsidering the regulation of coal combustion waste, with a decision expected in late 2012. Depending on the outcome of thatdecision, demand for coal fired electricity generation could be adversely impacted.Federal Regulation of the Sale and Transportation of GasVarious aspects of our gas operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates thetransportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In 1989,Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controlsaffecting wellhead sales of natural gas effective January 1, 1993. While "first sales" by producers of natural gas, and all sales of condensate and natural gasliquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future.Regulations and orders set forth by the Federal Energy Regulatory Commission also impact our gas business to a certain degree. Although the FederalEnergy Regulatory Commission does not directly regulate our gas production activities, the Federal Energy Regulatory Commission has stated that it intendsfor certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commissioncontinues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of competitive auctions and whetherchanges to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term34contracts. Additional Federal Energy Regulatory Commission orders have been adopted based on this review with the goal of increasing competition for naturalgas markets and transportation.The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilitiespreviously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over servicesprovided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. In addition, theFederal Energy Regulatory Commission's approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gatheringcompanies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services inareas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippersin the future.We own certain natural gas pipeline facilities that we believe meet the traditional tests which the Federal Energy Regulatory Commission has used toestablish a pipeline's status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdictionAdditional proposals and proceedings that might affect the gas industry may be pending before Congress, the Federal Energy Regulatory Commission,the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In thepast, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies willcontinue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations willhave a significantly adverse effect upon the capital expenditures, earnings or competitive position of CONSOL Energy or its subsidiaries. No material portionof our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.State Regulation of Gas OperationsOur gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulationincludes requiring permits for the siting and construction of well pads and roads, drilling of wells, bonding requirements, protection of ground water andsurface water resources and protection of drinking water supplies, the method of drilling and casing wells, the surface use and restoration of well sites, gasflaring, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane inrelation to active mining. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/orservices. Other state regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory takerequirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in thefuture. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although wedo not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdensmay affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.Ownership of Mineral RightsCONSOL Energy acquires ownership or leasehold rights to coal and gas properties prior to conducting operations on those properties. As is customaryin the coal and gas industries, we have generally conducted only a summary review of the title to coal and gas rights that are not in our development plans, butwhich we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our land records to determine control ofmineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a well-developed ownership position relating to our coal control;however, our ownership of oil and gas rights, particularly those rights that we acquired in connection with our historic coal operations, is less developed. Aswe continue to review our land records and confirm title in anticipation of development, we expect that adjustments to our ownership position (either increasesor decreases) will be required.Prior to the commencement of development operations on coal or gas properties, we conduct a thorough title examination and perform curative work withrespect to significant defects. We are typically responsible for the cost of curing any title defects. We generally will not commence operations on a property untilwe have cured any material title defects on such property. We have completed title work on substantially all of our coal and gas producing properties andbelieve that we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.A recent decision by the intermediate appellate court in Pennsylvania in a case captioned Butler v. Powers (Pa. Superior35Ct., No. 1795 MDA 2010) did not change the law of Pennsylvania with respect to the ownership of Marcellus Shale gas rights, but in remanding the case tothe trial court for further proceedings, it called into question the applicability of a long-standing presumption known as the Dunham Rule to gas in theMarcellus Shale. The Dunham Rule is a presumption that a reservation or conveyance of minerals does not reserve or convey oil and gas absent an expressreference to oil and gas. We believe that the Pennsylvania courts will ultimately confirm that the Dunham Rule applies to Marcellus Shale gas; however, if thePennsylvania courts were to hold otherwise, we could be exposed to lawsuits challenging our rights to Marcellus Shale gas in some of our Pennsylvaniaproperties where our rights derive from persons who did not also own the mineral rights and we may have to incur substantial additional costs to perfect ourgas title in those Pennsylvania properties.The ownership of CBM is an issue under the laws of some states, including states in which we operate. The following summary sets forth an analysisof provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and arequalified in their entirety by reference to the provisions of applicable law and rights and the laws relating to traditional natural gas resources may differmaterially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report on Form 10-K.Pennsylvania In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can besold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under theterms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. Asa result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership orleasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam. We believe that under Pennsylvania law, a coallessee under a lease to exhaustion would be in the same position as the coal owner with respect to ownership of the CBM.VirginiaThe Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM, absent evidence to the contrary. The situationmay be different if there is any expression in the severance deed indicating that more than mere coal is conveyed. Virginia courts have also found that the ownerof the CBM does not have the right to fracture the coal in order to retrieve the CBM and that the coal operator has the right to ventilate the CBM in the course ofmining.In Virginia, we believe that we control the relevant property rights in order to capture gas from our producing properties. When necessary, we utilize anadministrative procedure established by Virginia law that permits the development of CBM by an operator in those instances where the owner of the CBM hasnot leased it to the operator or in situations where there are conflicting claims of ownership of the CBM within a drilling unit. The general practice is to “forcepool” both the coal owner and the gas owner by filing an application with and obtaining an order from the Virginia Gas and Oil Board that permits thedevelopment of the CBM in the drilling unit notwithstanding lack of control of the CBM or conflicting claims of ownership. Any royalties otherwise payableto conflicting claimants are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gasand Oil Board does not make ownership decisions. Several lawsuits are pending in Virginia state courts and several purported class action lawsuits arepending in the Federal District Court for the Western District of Virginia in Abingdon, Virginia, including two lawsuits to which a CONSOL Energysubsidiary is named as a defendant, which seek, among other things, a court order establishing ownership of the CBM relating to the royalties currently heldin escrow.West VirginiaThe ownership of CBM is largely an open question in West Virginia. The West Virginia Supreme Court has held that under a conventional oil and gaslease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produceCBM. The West Virginia courts have not further clarified who owns CBM in West Virginia.West Virginia has enacted the Coalbed Methane Wells and Units Act (the West Virginia Act), regulating the commercial recovery and marketing ofCBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes tojudicial resolution, it contains provisions similar to Virginia's force pooling law described above. Under the pooling provisions of the West Virginia Act, anapplicant who proposes to drill can prosecute an administrative proceeding with the West Virginia Coalbed Methane Review Board to obtain authority toproduce36CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participationin the drilling (e.g., royalty or owner), but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within theboundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coaland title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from eitherthe coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production ofCBM from that well.Other StatesWe have rights to extract CBM where we have coal rights in other states. The ownership of CBM in the Illinois Basin and certain other western basinsmay be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate intereststo extract and produce CBM in these other statesAvailable InformationCONSOL Energy maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energy makes available, free of charge, on thiswebsite our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnishedpursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the 1934 Act), as soon as reasonably practicable after such reports areavailable, electronically filed with, or furnished to the SEC, and are also available at the SEC's website www.sec.gov.Executive Officers of the RegistrantIncorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Directors and Executive Officers of CONSOLEnergy” (included herein pursuant to Item 401 (b) of Regulation S-K).ITEM 1A.Risk FactorsInvestment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factorsrelated to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities todecline and result in a loss.Deterioration in the global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financialmarkets, may have adverse impacts on our business and financial condition that we currently cannot predict.Economic conditions in a number of industries in which our customers operate, such as electric power generation and steel making, substantiallydeteriorated in recent years and reduced the demand for natural gas and coal. Although global industrial activity recovered in 2010 from 2009 levels, thecontinuation of the recovery, especially for industries in the United States and Europe, is uncertain. During recent years, financial markets in the UnitedStates, Europe and Asia also experienced unprecedented turmoil and upheaval. This was characterized by extreme volatility and declines in security prices,severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financialinstitutions and an unprecedented level of intervention from the United States federal government and other governments. Although we cannot predict theimpacts, renewed weakness in the economic conditions of any of the industries we serve or in the financial markets could materially adversely affect ourbusiness and financial condition. For example:•demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact therevenues, 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 therevenues, margins and profitability of our metallurgical coal business including our ability to sell our high volatile steam coal as higher-pricedmetallurgical coal;•the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and theamount 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 forexploration and/or development of our coal or gas reserves; and•our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their37obligations or seek bankruptcy protection.A significant or extended decline in the prices CONSOL Energy receives for our coal and natural gas could adversely affect our operatingresults and cash flows.Our financial results are significantly affected by the prices we receive for our coal and natural gas. Extended or substantial price declines for coal wouldadversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. Pricesof coal may fluctuate due to factors beyond our control such as overall domestic and global economic conditions; the consumption pattern of industrialconsumers, electricity generators and residential users; increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to makesteel which do not use furnace coke, an intermediate product produced from metallurgical coal; technological advances affecting energy consumption;domestic and foreign government regulations; price and availability of alternative fuels; price of foreign imports; and weather conditions. Any adverse changein these factors could result in weaker demand and possibly lower prices for our coal production, which would reduce our revenues.Gas prices are closely linked to supply of natural gas and consumption patterns in the United States of the electric power generation industry and certainindustrial and residential patterns where gas is the principal fuel. Natural gas prices are very volatile, and even relatively modest drops in prices cansignificantly affect our financial results and impede growth. Changes in natural gas prices have a significant impact on the value of our reserves and on ourcash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we choose not toengage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas prices than our competitorswho engage in hedging arrangements to a greater extent than we do. Prices for natural gas may fluctuate widely in response to relatively minor changes in thesupply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreignsupply of natural gas; the price of foreign imports; overall domestic and global economic conditions; the consumption pattern of industrial consumers,electricity generators and residential users; weather conditions; technological advances affecting energy consumption; domestic and foreign governmentalregulations; proximity and capacity of gas pipelines and other transportation facilities; and the price and availability of alternative fuels. Many of these factorsmay be beyond our control. In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues to faceconcerns of oversupply due to the success of new shale plays and continued drilling in these plays, despite lower gas prices, to meet drilling commitments.Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levelsfor an extended period would negatively affect us in several ways. These include reduced cash flow, which would decrease funds available for capitalexpenditures employed to replace reserves or increase production. For example, natural gas prices recently fell to ten year lows and we recently announced asignificant reduction in the number of wells expected to be drilled in our Noble joint venture. Also, our access to other sources of capital, such as equity orlong-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we canproduce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if ourestimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down,as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever eventsor changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may notbe recoverable or whenever management's plans change with respect to those assets. We may incur impairment charges in the future, which could have anadverse effect on our results of operations in the period taken.We expect in the future that we and our joint venture partners will increase drilling activity in areas of shale formations which may also contain naturalgas liquids and/or oil. The prices for natural gas liquids and oil are volatile for reasons similar to those described above regarding natural gas. If we discoverand produce significant amounts of natural gas liquids or oil, our results of operation may be adversely affected by downward fluctuations in natural gasliquids and oil prices.If coal customers do not extend existing contracts or do not enter into new long-term coal contracts, profitability of CONSOL Energy'soperations could be affected.During the year ended December 31, 2011, approximately 84% of the coal CONSOL Energy produced was sold under long-term contracts (contractswith terms of one year or more). If a substantial portion of CONSOL Energy's long-term contracts are modified or terminated or if force majeure is exercised,CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts are not at the same level of profitability. If existingcustomers do not honor current contract commitments, our revenue would be adversely affected. The profitability of our long-term coal supply contractsdepends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors.Price changes, if any, provided in long-term supply contracts may not reflect our cost38increases, and therefore, increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions in our long-termcoal contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result,CONSOL Energy may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time totime, or our cost structure) and long-term contracts may not contribute to our profitability.The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.For the year ended December 31, 2011, we derived over 10% of our total revenues from sales to one customer individually and more than 30% of ourtotal revenue from sales to our four largest coal and gas customers. At December 31, 2011, we had approximately seventeen coal supply agreements with thesecustomers that expire at various times from 2012 to 2028. We are currently discussing the extension of existing agreements or entering into new long-termagreements with some of these customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us underlong-term coal supply agreements. If any one of these four customers were to significantly reduce their purchases of coal from us, or if we were unable to sellcoal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer.Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contractswith us.Our ability to receive payment for coal and gas sold and delivered depends on the continued creditworthiness of our customers. Some power plantowners may have credit ratings that are below investment grade. We also have been increasing exports to international customers and may have exposure totheir creditworthiness. If the creditworthiness of our customers declines significantly, our $200 million accounts receivable securitization program and ourbusiness could be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation,our revenues will decrease and we may have to reduce production at our mines until our customer's contractual obligations are honored.The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal orimpair our ability to supply coal to our customers. Similarly, our gas business depends on gathering, processing and transportation facilitiesowned by others and the disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas.Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. Disruption of transportationservices because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could temporarily impair our ability tosupply coal to customers and adversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as aresult, the cost of delivery is a critical factor in a customer's purchasing decision. Increases in transportation costs could make our coal less competitive.We gather, process and transport our gas to market by utilizing pipelines and facilities owned by others. If pipelines and facilities do not exist near ourproducing wells, if pipeline or facility capacity is limited or if pipeline or facility capacity is unexpectedly disrupted, our gas sales could be limited, reducingour profitability. If we cannot access processing pipeline transportation facilities, we may have to reduce our production of gas or vent our produced gas to theatmosphere because we do not have facilities to store excess inventory. If our sales of gas are reduced because of transportation or processing constraints, ourrevenues will be reduced, and our unit costs will also increase. If pipeline quality tariffs change, we might be required to install additional processingequipment which could increase our costs. The pipeline could also curtail our flows until the gas delivered to their pipeline is in compliance.Competition within the coal and natural gas industries may adversely affect our ability to sell our products. Increased competition or a loss ofour competitive position could adversely affect our sales of, or our prices for, our coal and natural gas products, which could impair ourprofitability.CONSOL Energy competes with coal producers in various regions of the United States and with some foreign coal producers for domestic salesprimarily to electric power generators. CONSOL Energy also competes with both domestic and foreign coal producers for sales in international markets.Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources,including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric and wind power. CONSOL Energy sells coal to foreign electricitygenerators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and39competition. Increases in coal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. Ifovercapacity results, prices could fall or we may not be able to sell our coal, which would reduce revenue.The gas industry is intensely competitive with companies from various regions of the United States. We compete with these companies and we maycompete with foreign companies for domestic sales. Many of the companies we compete with are larger and have greater financial, technological, human andother resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. In addition, largercompanies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace natural gas we produce or to grow ourproduction. Our ability to acquire additional properties and to discover new natural gas resources also depends on our ability to evaluate and select suitableproperties and to consummate these transactions in a highly competitive environment.We could be negatively affected if we fail to maintain satisfactory labor relations.As of December 31, 2011, we had 9,157 employees. Approximately 32% of these employees are represented by the United Mine Workers of America(UMWA) and represented operations generated approximately 48% of our U.S. coal production during the year ended December 31, 2011. Relations with ouremployees and, where applicable, organized labor relations are important to our success. If we do not maintain satisfactory labor relations with our organizedand non-represented employees, we may incur strikes, other work stoppages or have reduced productivity.The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmentalstandards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plantswith alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energysources. A reduction in the use of coal for electric power generation could decrease the volume of our coal sales and adversely affect ourresults of operation.Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air along with fineparticulate matter and carbon dioxide when coal is burned. Complying with regulations on these emissions can be costly for electric power generators. Forexample, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, usesulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be morecostly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant andemission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants.Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which electric power generators switch to alternative fuel couldmaterially affect us. Adoption of the Cross-State Air Pollution Rule (CASPR) in July 2011 (to be effective January 1, 2012, but currently subject to a stay) andthe Mercury and Air Toxic Standards Rule (MATS) in December 2011 requiring reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, andparticulate matter may require the installation of additional costly control technology or the implementation of other measures, including trading of emissionallowances and switching to alternative fuels. These additional reductions in permissible emission levels of impurities by coal-fired plants will likely make itmore costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future.Apart from actual and potential regulation of emissions from coal-fired plants, state and federal mandates for increased use of electricity from renewableenergy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewableenergy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although noneof these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewableenergy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domestic electric power generators asa result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce thedemand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.40Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for coal andnatural gas and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our coal and gasassets.While climate change legislation in the U.S. is unlikely in the next several years, the issue of global climate change continues to attract considerablepublic and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs), such ascarbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce, results in the creation of carbon dioxide emissions into theatmosphere by coal and gas end users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely to continue to bemade at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adoptedmeasures requiring reduction of GHGs within state boundaries. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries(including the United States but has not been ratified by the United States) expires in 2012. Regulation of GHGs could occur in the United States pursuant tothe Environmental Protection Agency (EPA) regulation under the Clean Air Act. On December 23, 2010 the EPA announced that it will propose standards forGHG emissions for gas, oil and coal fired power plants in July 2011 and issue final standards in May 2012. These proposed standards are now scheduled tobe published in early 2012. Apart from governmental regulation, on February 4, 2008, three of Wall Street's largest investment banks announced that they hadadopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants whichmay make it more difficult for utilities to obtain financing for coal-fired plants.If comprehensive regulation focusing on GHGs emission reductions is adopted for the United States by the EPA or in other countries where we sell coal,or if utilities were to have difficulty obtaining financing in connection with coal-fired plants, it may make it more costly to operate fossil fuel fired (especiallycoal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of theregulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantiallyincreasing the demand for natural gas. Apart from actual regulation, uncertainty over the regulation of GHG emissions may inhibit utilities from investing inthe building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal orpossibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decreasedemand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customersmay also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emissionstandards.In addition, coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane has a greater GHG effectthan carbon dioxide. Our gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into theatmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to further reduce our methaneemissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhapscurtail coal production. The amount of coalbed methane we capture is reported, on a voluntarily basis, to the U.S. Department of Energy. We have recorded theamounts we have captured since the early 1990's.Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs incompeting producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers.Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.Our coal mining and natural gas operations are subject to operating risks, which could increase our operating expenses and decrease ourproduction levels which could adversely affect our results of operations. Our coal and gas operations are also subject to hazards and anylosses or liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.Our coal mining operations are predominantly underground mines. These mines are subject to a number of operating risks that could disruptoperations, decrease production and increase the cost of mining at particular mines for varying lengths of time thereby adversely affecting our operatingresults. In addition, if coal production declines, we may not be able to produce sufficient amounts of coal to deliver under our long-term coal contracts.CONSOL Energy's inability to satisfy contractual obligations could result in our customers initiating claims against us. The operating risks that may have asignificant impact on our coal operations include:41•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 roofand the side walls of the mine;•equipment failures or repairs;•fires, explosions or other accidents;•weather conditions; and•security breaches or terroristic acts.Our exploration for and production of natural gas also involves numerous operating risks. The cost of drilling, completing and operating our shalegas wells, shallow oil and gas wells and coalbed methane (CBM) wells is often uncertain, and a number of factors can delay or prevent drilling operations,decrease production and/or increase the cost of our gas operations at particular sites for varying lengths of time thereby adversely affecting our operatingresults. The operating risks that may have a significant impact on our gas operations include:•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 inhydraulic 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.Although we maintain insurance for a number of hazards, we may not be insured or fully insured against the losses or liabilities that could arise from asignificant accident in our coal or gas operations.A decrease in the availability or increase in the costs of commodities or capital equipment used in mining operations could decrease our coalproduction, impact our cost of coal production and decrease our anticipated profitability.Coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capitalequipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities andcapital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in ouroperations could impact our mining operations costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a readysubstitute.We rely upon third party contractors to provide various field services to our coal and gas operations. A decrease in the availability of or anincrease in the prices charged by third party contractors or failure of third party contractors to provide quality services to us in a timelymanner could decrease our production, increase our costs of production, and decrease our anticipated profitability.We rely upon third party contractors to provide key services to our gas operations. We contract with third parties for well services, related equipment,and qualified experienced field personnel to drill wells and conduct field operations. The demand for these field services in the natural gas and oil industry canfluctuate significantly. Higher oil and natural gas prices generally stimulate increased demand causing periodic shortages. These shortages may lead toescalating prices for drilling equipment, crews and associated supplies, equipment and services. Shortages may lead to poor service and inefficient drillingoperations and increase the possibility of accidents due to the hiring of inexperienced personnel and overuse of equipment by contractors. In addition, the costsand delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtainnecessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or increases in the costs of,drilling equipment, crews42and associated supplies, equipment and field services in the future. We also use third party contractors to provide construction and specialized services to ourmining operations. A decrease in the availability of field services or equipment and supplies, an increase in the prices charged for field services, equipmentand supplies, or the failure of third party contractors to provide quality field services to us, could decrease our coal and gas production, increase our costs ofcoal and gas production, and decrease our anticipated profitability.We attempt to mitigate the risks involved with increased industrial activity by entering into “take or pay” contracts with well service providers whichcommit them to provide field services to us at specified levels and commit us to pay for field services at specified levels even if we do not use those services.However, these contracts expose us to economic risk. For example, if the price of natural gas declines and it is not economical to drill and produce additionalnatural gas, we may have to pay for field services that we did not use. This would decrease our cash flow and raise our costs of production.For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which if wecannot obtain in a timely manner would reduce our production, cash flow and results of operations.Most coal producers in the eastern U.S. are being impacted by government regulations and enforcement to a much greater extent than a few years ago,particularly in light of the renewed focus by environmental agencies and the government generally on the mining industry, including more stringentenforcement and interpretation of the laws that regulate mining. The pace with which the government issues permits needed for new operations and for on-goingoperations to continue mining has negatively impacted expected production, especially in Central Appalachia. Environmental groups in Southern West Virginiaand Kentucky have challenged state and U.S. Army Corps of Engineers permits for mountaintop and types of surface mining operations on various grounds.The most recent challenges have focused on the adequacy of the Corps of Engineers analysis of impacts to streams and the adequacy of mitigation plans tocompensate for stream impacts resulting from valley fill permits required for mountaintop mining. These challenges have also enhanced the EPA's oversightand involvement in the review of permits by state regulatory authorities. In 2007, the U.S. District Court for the Southern District of West Virginia found otheroperators' permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversed that decision, findingthat the permits were adequate. However, since that reversal, the EPA began to more critically review valley fill permits and permits for all types of coal miningoperations, and has been recommending that a number of permits be denied because of alleged concerns by the EPA of potential impacts to water quality instreams below mining operations, with cumulative impacts of mining on watersheds. The EPA's objections and an enhanced review process that was beingimplemented under a federal multi-agency memorandum of understanding effectively held up the issuance of permits for all types of mining operations thatrequire Clean Water Act Section 402 discharge permits and Section 404 dredge and fill permits, including surface facilities for underground mines. Although aportion of the EPA's enhanced review process was invalidated in October 2011, in part because the EPA failed to follow public notice and rulemakingrequirements, normal permitting has not resumed. Also, the EPA may elect to seek to adopt regulations to codify its enhanced review process. CONSOLEnergy's surface and underground operations have been impacted to a limited extent to date, but future permits may be delayed if the EPA continues to seek toexercise enhanced oversight and involvement in state permit programs. In addition, the length of time needed to bring a new mine into production has increasedby several years because of the increased time required to obtain necessary permits. These delays or denials of mining permits could reduce our production,cash flow and results of operations.Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others thatgovern our business may increase our costs of doing business for both coal and natural gas, and may restrict both our coal and gasoperations.We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating toprotection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the management and disposalof hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plant and wildlifeprotection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in ourmines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying withthese requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitiveposition. For example, we have agreed to commence operation by May 30, 2013, of a new advanced waste water treatment plant to treat the discharge of minewater from our Blacksville #2, Loveridge and Robinson Run mines at a total estimated cost of approximately $200 million. In addition, we could incursubstantial costs as a result of violations under environmental laws. Any additional laws, regulations and other legal requirements enacted or adopted byfederal, state and local, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of theenvironment matters could further affect our costs of43operations and competitive position.For example, the federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges intoregulated surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge ofpollutants into regulated waters. The Clean Water Act federal regulations and corresponding state laws and regulations require permits for discharges frommining and gas operations that include discharge limits that are adequate to protect existing stream uses and aquatic life and, for impaired streams, that areadequate to eliminate the impairment, which may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financialcondition and cash flows or may prevent us from being able to mine portions of our reserves. The Clean Water Act is being used by opponents of mountaintop removal mining as a means to challenge permits. In addition, CONSOL Energy incurs and will continue to incur costs associated with the investigationand remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund)and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bondingrequirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well siterestoration. If we fail to comply with statutes and regulations, we may be subject to penalties, which would decrease our profitability.Additionally, regulations applicable to the gas industry are under constant review for amendment or expansion at the federal and state level. Any futurechanges may affect, among other things, the pricing or marketing of gas production. For example, hydraulic fracturing is an important and common practicethat is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as Marcellus shale. The process involves theinjection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typicallyregulated by state oil and gas commissions. Hydraulic fracturing is currently exempt from regulation under the federal Safe Drinking Water Act, except forhydraulic fracturing using diesel fuel. The disposal of produced water, drilling fluids and other wastes in underground injection disposal wells is regulated bythe EPA under the federal Safe Drinking Water Act or by the states under counterpart state laws and regulations. The imposition of new environmentalinitiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from suchoperations. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the studyanticipated to be available by late 2012 and with a final report to be issued in 2014. Other federal agencies are also examining hydraulic fracturing, includingthe U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the Department of the Interior. In addition, legislation has beenintroduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also,some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulicfracturing in certain circumstances. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permitrequirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, some state and local governments inthe Marcellus Shale region in Pennsylvania and New York have considered or imposed a temporary moratorium on drilling operations using hydraulicfracturing until further study of the potential for environmental and human health impacts by the EPA or the relevant agencies are completed. No assurancecan be given as to whether or not similar measures might be considered or implemented in other jurisdictions in which our gas properties are located. If newlaws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, suchlegal requirements could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination of whethera well is commercially viable. New laws or regulations could also cause delays or interruptions or terminations of operations, the extent of which cannot bepredicted, and could reduce the amount of oil and natural gas that we ultimately are able to produce in commercially paying quantities from our gas properties,all of which could have a material adverse affect on our results of operation and financial condition.Our shale gas drilling and production operations require both adequate sources of water to use in the fracturing process as well as the abilityto dispose of water and other wastes after hydraulic fracturing. Our CBM gas drilling and production operations also require the removaland disposal of water from the coal seams from which we produce gas. If we cannot find adequate sources of water for our use or are unableto dispose of the water we use or remove it from the strata at a reasonable cost and within applicable environmental rules, our ability toproduce gas economically and in commercial quantities could be impaired.As part of our drilling and production in the Marcellus shale, we use hydraulic fracturing processes. Thus, we need access to adequate sources of waterto use in our Marcellus shale operations. Further, we must remove and dispose of the portion of the water that we use to fracture our shale gas wells that flowsback to the well-bore as well as drilling fluids and other wastes44associated with the exploration, development or production of natural gas. In addition, in our CBM drilling and production, coal seams frequently containwater that must be removed and disposed of in order for the gas to detach from the coal and flow to the well bore. Our inability to locate sufficient amounts ofwater with respect to our Marcellus Shale operations, or the inability to dispose of or recycle water and other wastes used in our Marcellus shale and our CBMoperations, could adversely impact our operations. For example, in Ohio, injection of gas well production fluids was temporarily suspended for undergroundinjection disposal wells near Youngstown while regulatory authorities investigate whether injection of wastewater into the wells is causing low categoryearthquakes in the area.Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and mayplace restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order ouroperations to be shut down based on safety considerations. A mine could be shut down for an extended period of time if a disaster were tooccur at it.Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Health and Safety Act of 1969 was adopted. TheFederal Coal Mine Safety and Health Act of 1977 expanded the enforcement of safety and health standards of the Coal Mine Health and Safety Act of 1969and imposed safety and health standards on all (non-coal as well as coal) mining operations. Regulations are comprehensive and affect numerous aspects ofmining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures, mine plans and other matters.The additional requirements of the Mine Improvement and New Emergency Response Act of 2006 (the Miner Act) and implementing federal regulationsinclude, among other things, expanded emergency response plans, providing additional quantities of breathable air for emergencies, installation of refugechambers in underground coal mines, installation of two-way communications and tracking systems for underground coal mines, new standards for sealingmined out areas of underground coal mines, more available mine rescue teams and enhanced training for emergencies. Most states in which CONSOL Energyoperates have programs for mine safety and health regulation and enforcement. We believe that the combination of federal and state safety and healthregulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Mostaspects of mine operations, particularly underground mine operations, are subject to extensive regulation. The various requirements mandated by law orregulation can place restrictions on our methods of operations, creating a significant effect on operating costs and productivity. In addition, governmentinspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations. If a disaster were to occur at oneof our mines, it could be shutdown for an extended period of time and our reputation with our customers could be materially damaged.Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmentalcontamination, which could result in liabilities to us.Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from orcaused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject toclaims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and othermedia. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned oroperated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of thecontamination or other damages, or for the entire share.We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject toextensive regulation. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authoritiesaccording to stringent environmental and safety standards. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage tothe environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and propertydamages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising outof failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as wellas for fines and penalties.In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that without treatment would result inviolations of state water quality standards that are set to protect fish and other aquatic life. CONSOL Energy has two operations with selenium discharges.CONSOL Energy and other coal companies are working to expeditiously develop cost effective means to remove selenium from mine water. If such technologyis not developed promptly, the only available effective treatment technologies are expensive to construct and operate which will increase coal production costs.45These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastesassociated with our operations, could result in costs and liabilities that could adversely affect us.CONSOL Energy has reclamation, mine closing and gas well plugging obligations. If the assumptions underlying our accruals areinaccurate, we could be required to expend greater amounts than anticipated.The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well asmost aspects of deep mining. Also, state laws require us to plug gas wells and reclaim well sites after the useful life of our gas wells has ended. CONSOLEnergy accrues for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water dischargewhere necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and ourexperience, were approximately $650 million at December 31, 2011. The amounts recorded are dependent upon a number of variables, including the estimatedfuture closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates.Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, ourfuture operating results could be adversely affected.Most states where we operate require us to post bonds for the full cost of coal mine reclamation (full cost bonding). West Virginia is not a full costbonding state. West Virginia has an alternative bond system (ABS) for coal mine reclamation which consists of (i) individual site bonds posted by thepermittee that are less than the full estimated reclamation cost plus (ii) a bond pool (Special Reclamation Fund) funded by a per ton fee on coal mined in theState which is used to supplement the site specific bonds if needed in the event of bond forfeiture. The Special Reclamation Fund is currently underfunded.Adequacy of the Special Reclamation Fund is an issue in a citizen suit pending in U.S. District Court in West Virginia. Given these facts, it is likely thatfunding for the Special Reclamation Fund will be increased to make it solvent through an increase in the per ton fee or from other funding sources, or the Statemay be forced by the court or the U.S. Office of Surface Mine Reclamation and Enforcement to convert to full cost bonding. An increase in the per ton fee mayreduce profit margins and/or make some operations unprofitable. Conversion to full cost bonding may exceed bonding capacity of individual miningcompanies and/or surety companies that would result in the need to post cash bonds or letters of credit which would reduce operating capital.CONSOL Energy faces uncertainties in estimating our economically recoverable coal and gas reserves, and inaccuracies in our estimatescould result in lower than expected revenues, higher than expected costs and decreased profitability.There are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond ourcontrol. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimatesbased on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economicallyrecoverable coal reserve estimates include:•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.In addition, we hold substantial coal reserves in areas containing Marcellus shale and other shales. These areas are currently the subject of substantialexploration for oil and gas, particularly by horizontal drilling. If a well is in the path of our mining for coal, we may not be able to mine through the wellunless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater.Horizontal wells with multiple laterals extending from the well pad may access larger oil and gas reserves than a vertical well which could result in highercosts. In future years, the cost associated with purchasing oil and gas wells which are in the path of our coal mining may make mining through those wellsuneconomical thereby effectively causing a loss of significant portions of our coal reserves. Similarly, natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gasprices, production levels, and operating and development costs. As a result, estimated quantities of proved gas reserves and projections of future productionrates and the timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account theresults of actual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production levels, and operating anddevelopment costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our46estimates of our gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of gasreserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimatesare based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates. The present value offuture net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base theestimated discounted future net cash flows from our proved gas reserves on historical average prices and costs. However, actual future net cash flows from ourgas and oil properties also will be affected by factors such as:•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.The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties willaffect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use whencalculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risksassociated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per thousand cubic feet, then the pre-taxpresent value using a 10% discount rate of our proved gas reserves as of December 31, 2011 would decrease from $2.9 billion to $2.7 billion. Thestandardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $1.7billion.Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For thesereasons, estimates of coal and gas reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and gas reserves willlikely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and gas reserves.We may incur additional costs and delays to produce coal and gas because we have to acquire additional property rights to perfect our title tocoal or gas rights.While chain of title for our coal estate generally has been established, there may be defects in it that we do not realize until we have committed todeveloping those properties or coal reserves. As such, the title to the coal estate that we intend to mine may contain defects. In order to conduct our miningoperations on properties where these defects exist, we may incur unanticipated costs perfecting title.Substantial amounts of acreage in which we believe we control gas rights are in areas where we have not yet done a thorough chain of title examination ofthe gas estate. A number of our gas properties were acquired primarily for the coal rights with the focus on the coal estate title, and, in many cases wereacquired years ago. In addition, we have acquired gas rights in substantial acreage from third parties who had not performed thorough chain of title work ontheir gas properties. Our practice, and we believe industry practice, is not to perform a thorough title examination on gas properties until shortly before thecommencement of drilling activities at which time we seek to acquire any additional rights needed to perfect our ownership of the gas estate for developmentand production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not befeasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce thegas without perfected ownership under an administrative process known as “pooling,” which require us to give notice to all potential claimants and payroyalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and thesecosts may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.In confirming title to the gas estate in Pennsylvania, we rely upon long standing Pennsylvania Supreme Court decisions. A recent decision by theintermediate appellate court in Pennsylvania in a case captioned Butler v. Powers (Pa. Superior Ct., No. 1795 MDA 2010) did not change the law ofPennsylvania, but in remanding the case to the trial court for further proceedings, it called into question the applicability of a long-standing presumptionknown as the Dunham Rule to gas in the Marcellus Shale. The Dunham Rule is a presumption that a reservation or conveyance of minerals does not transferthe ownership of oil and gas absent an express reference to oil and gas. While we believe that the Pennsylvania courts will ultimately confirm that the DunhamRule applies to Marcellus Shale gas, if the Pennsylvania courts were to hold otherwise, we could be exposed to lawsuits challenging our rights to MarcellusShale gas in some of our Pennsylvania properties where our47rights derive from persons who did not also own the mineral rights and we may have to incur substantial additional costs to perfect our gas title in thosePennsylvania properties.Our subsidiaries, primarily Fairmont Supply Company, is a co-defendant in various asbestos litigation cases which could result in makingpayments in the future that are material.One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant inapproximately 7,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Texas and Illinois. Because a very smallpercentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims arepart of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of thecases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmontmay be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity orcontribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from theseclaims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. For the year ended December 31, 2011, payments byFairmont with respect to asbestos cases have not been material. Other of our subsidiaries may also have asbestos claims against them. Our current estimatesrelated to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOLEnergy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financialposition, results of operations or cash flows of CONSOL Energy.CONSOL Energy and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.We are party to a number of legal proceedings in the normal course of business activities. Defending these actions, especially purported class actions,can be costly, and can distract management. For example, we are a defendant in five pending purported class action lawsuits dealing with such diverse mattersas the propriety of our acquisition of the noncontrolling interest of CNX Gas, our right to natural gas production in some areas, and asserting that we areresponsible for Hurricane Katrina and the damage it caused. There is the potential that the costs of defending litigation in an individual matter or theaggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position. See Note 24–Commitments andContingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legalproceedings.CONSOL Energy has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, couldresult in CONSOL Energy being required to expense greater amounts than anticipated.CONSOL Energy provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. AtDecember 31, 2011, the current and non-current portions of these obligations included:•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). However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded inaccordance with Employer Retirement Income Security Act of 1974 (ERISA) regulations. The other obligations are un-funded. In addition, the federalgovernment and several states in which we operate consider changes in workers' compensation and black lung laws from time to time. Such changes, ifenacted, could increase our benefit expense.Due to our participation in an underfunded multi-employer pension plan, we have exposure under that plan that extends beyond what ourobligation would be with respect to our employees and in the future we may have to make additional cash contributions to fund the pensionplan or incur withdrawal liability.Certain of our subsidiaries have been contributing to a multi-employer defined benefit pension plan (1974 Pension Trust) for United Mine Workers ofAmerica (UMWA) retirees under the terms of various National Bituminous Coal Wage Agreements (NBCWA) which those subsidiaries have entered into overthe years with the UMWA. The current NBCWA with the UMWA became effective July 1, 2011 and expires on December 31, 2016. All assets contributed tothe 1974 Pension Trust are pooled48and available to provide benefits for all participants and beneficiaries. As a result, contributions made by our signatory subsidiaries benefit employees ofCONSOL Energy and of other employers. For the plan year ended June 30, 2011, approximately 18% of retirees and surviving spouses receiving benefitsfrom the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy. The 1974 Pension Trust is overseen by a board of trustees,consisting of two union-appointed trustees and two employer-appointed trustees. The trustees' responsibilities include selection of the plan's investment policy,asset allocation, individual investment of plan assets and the administration of the plan. The benefits provided by the 1974 Pension Trust to the participatingemployees are determined based on age and years of service at retirement. The current NBCWA calls for contribution amounts to be paid to the 1974 PensionTrust by our signatory subsidiaries during the term of the NBCWA based principally on hours worked by our UMWA-represented employees at acontribution rate of $5.50 per hour.As of June 30, 2011, the most recent date for which information is available, the 1974 Pension Trust was underfunded. This determination was madein accordance with Employer Retirement Income Security Act of 1974 (ERISA) calculations, with a total actuarial asset value of $5.1 billion and a totalactuarial accrued liability of $6.6 billion. Under the Pension Protection Act of 2006 (Pension Protection Act), a funded percentage of 80% should bemaintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage of less than 80% it will be deemed to be“endangered” or “seriously endangered” if the number of years to reach a projected funding deficiency equals 7 or less and if less than 65%, it will be deemedto be in “critical” status. The funded percentage certified by the actuary for the 1974 Pension Trust was determined to be approximately 76.5% under thePension Act. On October 21, 2011, the signatory subsidiaries of CONSOL Energy received notice from the trustees of the 1974 Pension Trust stating that the1974 Pension Plan is considered to be in “seriously endangered” status for the plan year beginning July 1, 2011 due to the funded percentage and projectedfunding deficiency. As a result, the Pension Protection Act requires the 1974 Pension Trust to adopt a funding improvement plan no later than May 25, 2012,to improve the funded status of the plan, which may include increased contributions to the 1974 Pension Trust from employers in the future. Because the2011 NBCWA established our signatory subsidiaries contribution obligations through December 31, 2016, our signatory subsidiaries' contributions tothe 1974 Pension Trust should not increase during the term of the NBCWA as a consequence of any funding improvement plan adopted by the 1974 PensionTrust to address the plan's seriously endangered status.Upon expiration of the 2011 NBCWA, our signatory subsidiaries could be required to increase contributions to the 1974 Pension Trust in amounts thatcould be material to our financial position and results of operations or cash flows. In the event our subsidiaries were to withdraw from the 1974 PensionTrust, CONSOL Energy and its subsidiaries would be liable for a proportionate share of such pension plan's unfunded vested benefits, as determined by theplan's actuary. Based on the information available from the 1974 Pension Trust's administrators, we believe that our portion of the contingent liabilityrepresented by the plan's unfunded vested benefits, in the case of the withdrawal of our signatory subsidiaries from the plan or in the case of the termination ofthe plan, would be material to our financial position and results of operations. As of June 30, 2011 this withdrawal liability was estimated at approximately$1.2 billion. In the event that any other contributing employer withdraws from the 1974 Pension Trust and such employer (or any member in its controlledgroup) cannot satisfy their obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would beliable for an increase in our proportionate share of the 1974 Pension Trust's unfunded vested benefits at the time of the withdrawal from the plan or itstermination.If lump sum payments made to retiring salaried employees pursuant to CONSOL Energy's defined benefit pension plan exceed the total of theservice cost and the interest cost in a plan year, CONSOL Energy would need to make an adjustment to operating results equaling theunrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in anadjustment that could reduce operating results. CONSOL Energy's defined benefit pension plan for salaried employees allows such employees to receive a lump-sum distribution for benefits earned upthrough December 31, 2005 in lieu of annual payments when they retire from CONSOL Energy. Employers' Accounting for Settlements and Curtailments ofDefined Benefit Pension Plans for Terminations Benefits requires that if the lump-sum distributions made for a plan year exceed the total of the service costand interest cost for the plan year, CONSOL Energy would need to recognize for that year's results of operations an adjustment equaling the unrecognizedactuarial gain or loss resulting from each individual who received a lump sum in that year. This type of adjustment may result in a reduction in operatingresults.Acquisitions that we have completed, acquisitions that we may undertake in the future, as well as expanding existing company mines, involvea number of risks, any of which could cause us not to realize the anticipated benefits and to the extent we plan to engage in joint ventures anddivestitures, we do not control the timing of these and they may not provide anticipated benefits.We have completed several acquisitions and investments in the past including the approximately $3.5 billion Dominion49Acquisition, which closed on April 30, 2010. We also continually seek to grow our business by adding and developing coal and gas reserves throughacquisitions and by expanding the production at existing mines and existing gas operations. If we are unable to successfully integrate the companies,businesses or properties we acquire, we may fail to realize the expected benefits of the acquisition and our profitability may decline and we could experience amaterial adverse effect on our business, financial condition, or results of operations. Acquisitions, mine expansion and gas operation expansion involvevarious inherent risks, including:•uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent andother 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 theexpansion or the acquisition opportunity; and•we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.From time to time part of our business and financing plans include entering into joint venture arrangements and the divestiture of certain assets.However, we do not control the timing of divestitures or joint venture arrangements and delays in entering into divestitures or joint venture arrangements mayreduce the benefits from them. In addition, the terms of divestitures and joint venture arrangements may make a substantial portion of the benefits weanticipate receiving from them to be subject to future matters that we do not control.We have entered into two significant gas joint ventures. These joint ventures restrict our operational and corporate flexibility; actions takenby our joint venture partners may materially impact our financial position and results of operation; and we may not realize the benefits weexpect to realize from these joint ventures. In the second half of 2011 CONSOL Energy, through its principal gas operations subsidiary, CNX Gas Company LLC (CNX Gas Company), enteredinto joint venture arrangements with Noble Energy, Inc. (Noble Energy) and Hess Ohio Developments, LLC (Hess) regarding our shale gas assets. We sold a50% undivided interest in approximately 628 thousand net acres of Marcellus shale oil and gas assets to Noble Energy and a 50% undivided interest in nearly200 thousand net Utica shale acres in Ohio. The following aspects of these joint ventures could materially impact CONSOL Energy:•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 controlthe development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditureprograms that each party must participate in unless the parties mutually agree to change such programs or, in certain limited circumstances in the case ofthe 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 ourfinancial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and the otherparties 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 unmetfinancial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas ofmutual interest. •Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We couldincur 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 aportion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction withHess Ohio Developments, LLC (Hess) in which approximately $534 million of the total anticipated consideration of $594 million is dependentupon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wellsare drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of thesethird party obligations is outside our control. The inability or failure of a joint venturer to pay its portion of development costs, including ourcarried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss ofrights to develop the oil and gas properties held by that joint venture;50•Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per millionBritish 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 suspendedbeginning on December 1, 2011. We cannot predict when this suspension will be lifted and Noble Energy's obligation to pay the carried costswill resume. This suspension has the effect of requiring us to incur our entire 50 percent share of the drilling and completion costs for new wellsduring 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, anytransfer of our interests in the Noble Energy joint venture assets or our selling or otherwise transferring control of CNX Gas Company. The Hessjoint development agreement prohibits prior to October 21, 2014, unless Hess consents in its sole discretion, any transfer of our interests in theHess 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 terminateprojects and distract our officers and directors from focusing their time and effort on our business.We may also enter into other joint venture arrangements in the future which could pose risks similar to risks described above.CONSOL Energy's rights plan may have anti-takeover effects that may discourage a change of control even if doing so might be beneficial toour stockholders.On December 19, 2003, CONSOL Energy adopted a rights plan which, in certain circumstances, including a person or group acquiring, or thecommencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 15% of the outstandingshares of CONSOL Energy common stock, would entitle each right holder to receive, upon exercise of the right, shares of CONSOL Energy common stockhaving a value equal to twice the right exercise price. For example, at an exercise price of $80 per right, each right not otherwise voided would entitle its holdersto purchase $160 worth of shares of CONSOL Energy common stock for $80. Assuming that shares of CONSOL Energy common stock had a per sharevalue of $16 at such time, the holder of each right would be entitled to purchase ten shares of CONSOL Energy common stock for $80, or a price of $8 pershare, one half of its then market price. This and other provisions of CONSOL Energy's rights plan could make it more difficult for a third party to acquireCONSOL Energy, which could hinder stockholders' ability to receive a premium for CONSOL Energy stock over the prevailing market prices.The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition andresults of operations.As of December 31, 2011, our total indebtedness was approximately $3.198 billion of which approximately $1.5 billion was under our 8.00% seniorunsecured notes due April 2017, $1.25 billion was under our 8.25% senior unsecured notes due April 2020, $250 million was under our 6.375% seniornotes due 2021, $103 million was under our Baltimore Port Facility 5.75% revenue bonds due September 2025, $64 million of capitalized leases due through2021, and $31 million of miscellaneous debt. The degree to which we are leveraged could have important consequences, including, but not limited to: •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 andgas reserves or other general corporate requirements;•limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and•placing us at a competitive disadvantage compared to less leveraged competitors.Our senior secured credit facility and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes limit the incurrence of additionalindebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply withcertain financial covenants on a quarterly basis including a minimum interest coverage ratio, a maximum leverage ratio, and a maximum senior securedleverage ratio, as defined. Our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes impose anumber of restrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, selling assets and engaging inacquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have an adverse effect on us.51If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital orseek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt serviceobligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets oroperations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indentures governing our 8.00%, 8.25% and6.375% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtainthe proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.Unless we replace our gas reserves, our gas reserves and production will decline, which would adversely affect our business, financialcondition, results of operations and cash flows.Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and otherfactors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2011, production is expected to decline even if thoseproved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in adifferent manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, ourcash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiringadditional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptablecosts. Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expectedproduction. As of December 31, 2011, we had hedges on approximately 76.9 billion cubic feet of our 2012 natural gas production, 50.8 billion cubic feet ofour 2013 natural gas production, 44.0 billion cubic feet of our 2014 natural gas production, and 3.8 billion cubic feet of our 2015 natural gas production. Tothe extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:•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. If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market and recognize the adjustments throughcurrent year earnings. This may result in more volatility in our income in future periods.ITEM 1B.Unresolved Staff CommentsNone.ITEM 2.PropertiesSee “Coal Operations” and “Gas Operations” in Item 1 of this 10-K for a description of CONSOL Energy's properties.ITEM 3.Legal ProceedingsThe first through the nineteenth paragraphs of Note 24–Commitments and Contingent Liabilities in the Notes to the Audited Consolidated FinancialStatements in Item 8 of this Form 10-K are incorporated herein by reference.ITEM 4.Mine Safety and Health Administration Safety DataInformation concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform andConsumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this annual52report.PART IIITEM 5.Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity SecuritiesOur common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth for the periods indicated the rangeof high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the commonstock for the periods indicated: High Low DividendsYear Period Ended December 31, 2011 Quarter Ended March 31, 2011 $55.49 $45.49 $0.100 Quarter Ended June 30, 2011 $54.17 $45.86 $0.100 Quarter Ended September 30, 2011 $54.82 $33.93 $0.100 Quarter Ended December 31, 2011 $46.75 $31.70 $0.125Year Period Ended December 31, 2010 Quarter Ended March 31, 2010 $56.34 $42.28 $0.100 Quarter Ended June 30, 2010 $46.26 $33.73 $0.100 Quarter Ended September 30, 2010 $39.22 $31.21 $0.100 Quarter Ended December 31, 2010 $48.81 $36.67 $0.100As of December 31, 2011, there were 172 holders of record of our common stock.The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CONSOLEnergy to the cumulative shareholder return for the same period of a peer group and the Standard & Poor's 500 Stock Index. The peer group is comprised ofCONSOL Energy, Alliance Resource Partners, Alpha Natural Resources Inc., Anadarko Petroleum Corp., Apache Corp., Arch Coal Inc., Cabot Oil & GasCorp., Callon Petroleum Co., Chesapeake Energy Corp., Cimarex Energy Co., Comstock Resources Inc., Denbury Resources Inc., Devon Energy Corp.,Encana Corp., EOG Resources Inc., James River Coal Co., Newfield Exploration Co., Nexen Inc., Noble Energy Inc., Peabody Energy Corp., Penn VirginiaCorp., Pioneer Natural Resources Co., Rio Tinto PLC (ADR), St Mary Land & Exploration, Stone Energy Corp., Ultra Petroleum Corp., and WestmorelandCoal Co. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2006. The graphalso assumes that all dividends were reinvested and that the investments were held through December 31, 2011. 2006 2007 2008 2009 2010 2011CONSOL Energy Inc. 100.0 223.6 90.6 159.0 157.0 119.6Peer Group 100.0 182.8 66.9 118.2 150.1 112.8S&P 500 Stock Index 100.0 105.4 66.8 84.1 96.7 96.753Cumulative Total Shareholder Return Among CONSOL Energy Inc., Peer Group and S&P 500 Stock IndexThe above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).On January 27, 2012, CONSOL Energy's board of directors declared a regular quarterly dividend of $0.125 per share, payable on February 21, 2012,to shareholders of record on February 7, 2012.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,effective immediately.The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and noassurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will bepaid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results,contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factorsas the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.40 per share when our leverageratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 2.15 to 1.00 and our availability was approximately$1.2 billion at December 31, 2011. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and otherpayment limitations under the indentures. There were no defaults in the year ended December 31, 2011.See Part III, Item 12. “Security ownership of Certain Beneficial Owners and Management and Related Stockholders Matters” for information relating toCONSOL Energy's equity compensation plans.ITEM 6.Selected Financial DataThe following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. Theselected consolidated financial data for, and as of the end of, each of the years ended December 31, 2011, 2010, 2009, 2008 and 2007 are derived from ouraudited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2011presentation. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. Theselected consolidated financial and operating data should be read in conjunction with “Management's Discussion and Analysis of Financial Condition andResults of Operations” and the financial statements and related notes included in this annual report.54STATEMENT OF INCOME DATA(In thousands except per share data) For the Years Ended December 31, 2011 2010 2009 2008 2007Sales–Outside(A) $5,660,813 $4,938,703 $4,311,791 $4,181,569 $3,324,346Sales–Gas Royalty Interest(A) 66,929 62,869 40,951 79,302 46,586Sales–Purchased Gas(A) 4,344 11,227 7,040 8,464 7,628Freight–Outside(A) 231,536 125,715 148,907 216,968 186,909Other Income 153,620 97,507 113,186 166,142 196,728 Total Revenue and Other Income 6,117,242 5,236,021 4,621,875 4,652,445 3,762,197 Cost of Goods Sold and Other OperatingCharges (exclusive of depreciation, depletionand amortization shown below) 3,501,189 3,262,327 2,757,052 2,843,203 2,352,000Gas Royalty Interests' Costs 59,331 53,775 32,376 73,962 39,921Purchased Gas Costs 3,831 9,736 6,442 8,175 7,162Freight Expense 231,347 125,544 148,907 216,968 186,909Selling, General and Administrative Expenses 175,576 150,210 130,704 124,543 108,664Depreciation, Depletion and Amortization 618,397 567,663 437,417 389,621 324,715Interest Expense 248,344 205,032 31,419 36,183 30,851Taxes Other Than Income 344,460 328,458 289,941 289,990 258,926Abandonment of Long-Lived Assets 115,817 — — — —Loss on Debt Extinguishment 16,090 — — — —Transaction and Financing Fees 14,907 65,363 — — —Black Lung Excise Tax Refund — — (728) (55,795) 24,092 Total Costs 5,329,289 4,768,108 3,833,530 3,926,850 3,333,240Earnings Before Income Taxes 787,953 467,913 788,345 725,595 428,957Income Taxes 155,456 109,287 221,203 239,934 136,137Net Income 632,497 358,626 567,142 485,661 292,820Less: Net Income Attributable toNoncontrolling Interest — (11,845) (27,425) (43,191) (25,038)Net Income Attributable to CONSOL EnergyInc. Shareholders $632,497 $346,781 $539,717 $442,470 $267,782 Earnings Per Share: Basic(B) $2.79 $1.61 $2.99 $2.43 $1.47 Dilutive(B) $2.76 $1.60 $2.95 $2.40 $1.45 Weighted Average Number of Common SharesOutstanding: Basic 226,680,369 214,920,561 180,693,243 182,386,011 182,050,627 Dilutive 229,003,599 217,037,804 182,821,136 184,679,592 184,149,751 Dividends Paid Per Share $0.425 $0.400 $0.400 $0.400 $0.31055BALANCE SHEET DATA(In thousands) December 31, 2011 2010 2009 2008 2007Working (deficiency) capital $509,580 $(549,779) $(487,550) $(527,926) $(333,242)Total assets $12,525,700 $12,070,610 $7,775,401 $7,535,458 $6,333,490Short-term debt $— $484,000 $522,850 $722,700 $372,900Long-term debt (including current portion) $3,198,114 $3,210,921 $468,302 $490,752 $507,208Total deferred credits and other liabilities $4,348,995 $4,283,674 $3,849,428 $3,716,021 $3,325,231CONSOL Energy Inc. Stockholders' equity $3,610,885 $2,944,477 $1,785,548 $1,462,187 $1,214,419OTHER OPERATING DATA(unaudited) Years Ended December 31, 2011 2010 2009 2008 2007Coal: Tons sold (in thousands)(C)(D) 63,797 63,906 58,123 66,236 65,462Tons produced (in thousands)(D) 62,574 62,352 59,389 65,077 64,617Average sales price of tons produced ($ per ton produced)(D) $72.72 $61.35 $58.28 $48.77 $40.60Average production cost ($ per ton produced)(D) $52.22 $46.55 $44.87 $41.08 $33.68Recoverable coal reserves (tons in millions)(D)(E) 4,459 4,401 4,520 4,543 4,526Number of active mining complexes (at end of period) 12 12 11 17 15 Gas: Net sales volumes produced (in billion cubic feet)(D) 153.5 127.9 94.4 76.6 58.3Average sales price ($ per mcf)(D)(F) $4.90 $5.83 $6.68 $8.99 $7.20Average cost ($ per mcf)(D) $3.86 $3.90 $3.44 $3.67 $3.33Proved reserves (in billion cubic feet)(D)(G) 3,480 3,732 1,911 1,422 1,343CASH FLOW STATEMENT DATA(In thousands) For the Years Ended December 31, 2011 2010 2009 2008 2007Net cash provided by operating activities $1,527,606 $1,131,312 $1,060,451 $989,864 $558,633Net cash used in investing activities(H) $(578,524) $(5,543,974) $(845,341) $(1,098,856) $(972,104)Net cash provided by (used in) financingactivities $(606,140) $4,379,849 $(288,015) $205,853 $231,23956OTHER FINANCIAL DATA(Unaudited)(In thousands) For the Years Ended December 31, 2011 2010 2009 2008 2007Capital expenditures $1,382,371 $1,154,024 $920,080 $1,061,669 $743,114EBIT(I) $1,159,285 $653,458 $786,520 $685,574 $421,978EBITDA(I) $1,777,682 $1,221,121 $1,223,937 $1,075,195 $746,693Ratio of earnings to fixed charges(J) 3.53 2.74 11.76 10.67 7.48____________(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 byoperating segment.(B)Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding forpurposes 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 yearended 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 followingamount 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 apercentage of their net production, sales and reserves equal to CONSOL Energy's percentage equity ownership. For coal, the proportionate share ofrecoverable reserves for equity affiliates was 145, 172, 170, 171 and 179 tons at December 31, 2011, 2010, 2009, 2008 and 2007 respectively. Salesof 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 endedDecember 31, 2011, 2010, 2009, 2008 and 2007, respectively. For gas, amounts include 100% of CNX Gas' basis for all years presented; they excludethe noncontrolling interest reduction. There was no equity in affiliates at December 31, 2011, 2010, 2009 and 2008. The proportionate share of provedgas 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 endedDecember 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 $54,099related 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 tothe Dominion Acquisition and the purchase of CNX Gas Non-Controlling Interest, respectively. The year ended December 31, 2007 includes $296,724related 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, andabandonment of long-lived assets. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), incometaxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance withgenerally accepted accounting principles, management believes that they are useful to an investor in evaluating CONSOL Energy because they arewidely used in the coal industry as measures to evaluate a company's operating performance before debt expense and cash flow. Financial covenants inour credit facility include ratios based on EBITDA. EBIT and EBITDA do not purport to represent cash generated by operating activities and shouldnot 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 titledmeasures of other companies. Management's discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debtservice and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconcilement of EBITand EBITDA to financial net income is as follows:57 For the Years Ended December 31, 2011 2010 2009 2008 2007Net Income $632,497 $346,781 $539,717 $442,470 $267,782Add: Interest expense 248,344 205,032 31,419 36,183 30,851Less: Interest income (8,919) (7,642) (5,052) (2,363) (12,792)Less: Interest income included in black lungexcise tax refund — — (767) (30,650) —Add: Income tax expense 155,456 109,287 221,203 239,934 136,137Add: Loss on Debt Extinguishment 16,090 — — — —Add: Abandonment of Long-Lived Assets 115,817 — — — —Earnings before interest and taxes (EBIT) 1,159,285 653,458 786,520 685,574 421,978Add: Depreciation, depletion and amortization 618,397 567,663 437,417 389,621 324,715Earnings before interest, taxes and depreciation,depletion and amortization (EBITDA) $1,777,682 $1,221,121 $1,223,937 $1,075,195 $746,693(J)For purposes of computing the ratio of earnings to fixed charges, earnings represent income before income taxes plus fixed charges. Fixed chargesinclude (a) interest on indebtedness (whether expensed or capitalized), (b) amortization of debt discounts and premiums and capitalized expenses relatedto 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 OperationsGeneralFourth quarter demand for U.S. thermal and metallurgical coal continued to keep pace with the first three quarters of 2011. Demand for thermal coalfrom domestic electric generators decreased slightly from the previous year due to decreases in electricity demand and relatively low natural gas prices that havetaken some market share from coal generation. International demand for U.S. coals, however, has exceeded any reduction in demand from domestic electricgenerators. Total U.S. coal exports are likely to exceed 100 million tons for 2011 which is at least 20 million tons higher than 2010 levels.International demand for U.S. thermal coal slowed in the fourth quarter, but total 2011 thermal coal exports were almost double 2010 levels. Prices forspot coal delivered into Europe declined in the fourth quarter due to weak demand related to the economic slowdown and by weather conditions. Prices forexport thermal coal remain competitive relative to U.S. thermal coal customers. Longer-term fundamentals for thermal coal exports to Europe remain favorableas subsidized mining in Europe is phased-out, nuclear growth plans are curtailed and South African coals are pulled into Asian markets.Domestically, coal inventories at electric generators began to grow towards the end of the fourth quarter due to warmer than normal December weather andrelatively low natural gas prices. U.S. electric demand during the fourth quarter of 2011 was estimated to be slightly lower than 2010 levels due to a relativelymild start to the winter season. Coal inventories at electric utilities in CONSOL Energy 's traditional markets grew slightly during the fourth quarter butremain below recent years.Metallurgical coal demand for 2011 continued the strong pace set earlier this year as world blast furnace output grew an estimated 4.7% over 2010. Steelproduced from the blast furnace method uses metallurgical coal and drives metallurgical coal demand. China continues to provide the bulk of the world's blastfurnace iron production with almost 59% of world production, an increase of 6.3% compared to 2010. Although European steelmakers have shown signs of aslowdown, global production remains strong. In particular, production in the United States was up almost 13% compared to 2010, supported by a modestrebound in the North American auto sector.58Global supply of metallurgical coal began to normalize in the fourth quarter after conditions improved at Australian mines impacted by the Spring 2011flooding. International settlement prices have declined since the temporary supply and demand imbalance was resolved, but currently reflect the tight globalsupply and demand balance for metallurgical coal. CONSOL Energy is well positioned to take advantage of this market with its low cost Buchanan low-volatile operation, low cost high-volatile operations in Northern Appalachia and mid-vol operations set to open in early 2012.Natural gas markets enjoyed record demand in 2011 primarily driven by gas fired electric generation and an increase in industrial consumption. Someof this increase in demand came from electric generators taking advantage of relatively low prices and utilized more natural gas generation. Supply however,has continued to grow at very strong rates due to the abundance of new shale resources. This supply and demand imbalance is tempered by decreased importsof liquefied natural gas (LNG) and Western Canadian pipeline gas, as well as increased exports to Eastern Canada and Mexico. This supply response may notbe sufficient to bring the markets into balance and additional downward price pressures could be experienced in 2012.Longer-term rebalancing will be aided by declining conventional production and the shift in drilling towards oil and “liquids rich” gas plays. Thewidespread perception that shale gas production will yield lower and less volatile natural gas prices could spur additional demand as electric generators chooseto build additional high-efficiency baseload gas power plants. Additional demand will come from the petrochemical industry and developing sources ofdemand such as more wide-scale use of natural gas vehicles. CONSOL Energy continues to believe that natural gas will bring balance to CONSOL Energy'sportfolio of long-lived energy resources.A failure to return to normal weather patterns could have a negative short-term impact on CONSOL Energy's natural gas and domestic thermal coaldemand. Additionally, uncertainty in the short term economic outlook could lead to a slowing of global economic expansion. Economic uncertainty is currentlydriven by the European sovereign debt crisis, lingering high U.S. unemployment rates and instability in the Middle East oil-producing region. Thefundamental long-term drivers of CONSOL Energy's business remain unchanged as the global demand for low-cost, reliable sources of energy andmetallurgical coal remain strong in both the developed and developing world.CONSOL Energy engaged in several business and financing transactions in the year ended December 31, 2011. These transactions include thefollowing:•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.•On October 21, 2011, CNX Gas Company LLC (CNX Gas Company) completed a sale to a subsidiary of Hess Corporation (Hess) of 50% of itsnearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54 million, which is net of $5 million oftransaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to payapproximately $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.•On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certainMarcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of theCompany's undivided interest in certain of its existing Marcellus Shale wells and related leases. Cash proceeds of $485 million were received relatedto this transaction, which are net of $35 million transaction fees. Additionally, a note receivable has been recognized related to the two additional cashpayments 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. Subsequentto the transaction, an additional receivable of $17 million and a payable of approximately $980 thousand were recorded for closing adjustments andhave been included in Accounts and Notes Receivable - Other and Accounts Payable, respectively. The net loss on the transaction was $64 millionand was recognized in the Consolidated Statements of Income as Other Income. As part of the transaction, CNX Gas Company also received acommitment from Noble to pay one-third of the Company's working interest share of certain drilling and completion costs, up to approximately $2.1billion with certain restrictions. These restrictions include the suspension of carry if average natural gas Henry Hub prices are below $4.00 permillion 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.59 •On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operateeach company's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted forunder 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 $68million. The cash proceeds have been recorded as cash inflows of $60 million and $8 million in Distributions from Equity Affiliates and Proceedsfrom the Sale of Assets, respectively, on the Consolidated Statements of Cash Flow. The gain on the transaction was $7 million and was recognizedin the Consolidated Statements of Income as Other Income.•On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to whichCONSOL Energy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of MarcellusShale located in nine counties in southwestern Pennsylvania and north central West Virginia, in exchange for $193 million. The net gain of $41million is included in Other Income in the Consolidated Statements of Income.•CONSOL Energy incurred costs of approximately $15 million in the year ended December 31, 2011 related to the solicitation of consents from theholders of CONSOL Energy's outstanding 8.00% Senior Notes due 2017, 8.25% Senior Notes due 2020 and 6.375% Senior Notes due 2021. Theconsents allowed an amendment to the indentures for each of those notes, clarifying that the transactions such as those contemplated by the August2011 Asset Acquisition Agreements with Noble and Hess were permissible under those indentures.•In June 2011, the Bituminous Coal Operators Association (BCOA) and the United Mine Workers of America (UMWA) reached a new collectivebargaining agreement which will run from July 1, 2011 to December 31, 2016. That agreement, the National Bituminous Coal Wage Agreement of2011 (2011 NBCWA), covers approximately 2,900 employees of CONSOL Energy subsidiaries. The 2011 NBCWA is the successor agreement tothe 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 contractterm.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. Newinexperienced 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 representedemployees with over 20 years of credited service under the 1974 Pension Plan will receive a $1.00 per hour contribution (increasing to $1.50 perhour in 2014-2016) to the CDSP beginning January 1, 2012. Also beginning January 1, 2012, UMWA represented employees will have the right toelect 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 retireesin 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 definedcontribution 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 sickdays.•In June 2011, CONSOL Energy management decided to permanently idle its Mine 84 underground facility. This facility had been on idle statussince March 2009. Various options for the facility were explored, such as selling and operating with continuous miners, but management decided itwas in the best interest of the Company to abandon the underground workings of this facility and reallocate resources into more profitable coaloperations and Marcellus Shale drilling operations. The Company redeployed all of the movable equipment from the mine that could be used at otherlocations. The abandonment of this underground facility resulted in a $116 million charge to pre-tax earnings. See Note 10—Property, Plant andEquipment in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional disclosure. TheCompany 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 the60availability under the agreement from $700 million to $1.0 billion, decreases the interest rate and extends the term from May 6, 2014 to April 12,2016. The amended credit agreement continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries.•In April 2011, CONSOL Energy amended and extended its existing $1.5 billion senior secured credit agreement, which decreases the interest rateand extends the term from May 7, 2014 to April 12, 2016. The amended agreement continues to be secured by substantially all of the assets ofCONSOL Energy and certain of its subsidiaries.•On March 9, 2011, CONSOL Energy issued $250 million of 6.375% senior notes due March 2021. The Notes are guaranteed by substantially allof the Company's existing and future wholly owned domestic restricted subsidiaries. The Company issued the Notes with the intention of using thenet proceeds to repay its outstanding 7.875% senior secured notes due March 1, 2012, on or before their maturity. On April 11, 2011, CONSOLEnergy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenturegoverning the notes. By using the proceeds of the $250 million, 6.375% senior notes due March 2021 to effect this redemption, the Companyeffectively extended the maturity of the $250 million of long-term indebtedness by nine years at a lower interest rate. The redemption price includedprincipal 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 paidon these notes if they had been held to maturity.CONSOL Energy is managing several significant matters that may affect our business and impact our financial results in the future including thefollowing:•Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risksinclude (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations and (ii) increased scrutiny ofexisting safety regulations and the development of new safety regulations.•Federal and state environmental regulators are reviewing our operations more closely and more strictly interpreting and enforcing existingenvironmental 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 anadvanced technology mine water treatment plant and related facilities to reduce high levels of total dissolved solids in water discharges from certain ofour mines in Northern West Virginia, at a total estimated cost of approximately $200 million.•Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations couldrequire significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department ofInterior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM'sconsideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, couldmake 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 moreexpensive for our customers to operate their businesses, possibly inducing them to move to alternative fuel sources. For example, the EPA has issueda proposed rule that would regulate coal combustion residuals from coal fired electric generating facilities under the federal Resource Conservationand 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 finalrules are adopted consistent with either of the proposed alternatives, the cost of handling and disposal of coal combustion residuals could increasemaking it more expensive to generate electricity from coal. Another example is the Cross-State Air Pollution Rule (CSAPR) that was finalized by theEPA 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 regulatesthe amount of SO2 and NOx that power plants in 23 eastern states can emit in order to meet clean air requirements in downwind states. Anotherexample is the Mercury and Air Toxic Standards issued by the EPA on December 16, 2011. The new regulations, which will be published inFebruary 2012, set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include morestringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOX. Some older coal fired power plants may be retired orhave 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 ownedtreatment works (POTW) that treat municipal wastewater to accept wastewater from61Marcellus Shale operators. They called on operators to cease delivering wastewater to the POTWs by May 19, 2011. CONSOL Energy hasimplemented a re-cycle and re-use process of its Marcellus derived water for hydraulic fracturing operations, and will only safely dispose ofMarcellus wastewater in regulated, underground injection control wells.•CONSOL Energy continues to explore potential sales of non-core assets.Results of OperationsYear Ended December 31, 2011 Compared with Year Ended December 31, 2010Net Income Attributable to CONSOL Energy ShareholdersCONSOL Energy reported net income attributable to CONSOL Energy shareholders of $632 million, or $2.76 per diluted share, for the year endedDecember 31, 2011. Net income attributable to CONSOL Energy shareholders was $347 million, or $1.60 per diluted share, for the year ended December 31,2010.The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed$933 million of earnings before income tax for the year ended December 31, 2011 compared to $536 million for the year ended December 31, 2010. The totalcoal division sold 62.7 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, for the yearended December 31, 2011 compared to 63.0 million tons for the year ended December 31, 2010.The average sales price and average costs per ton for all active coal operations were as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeAverage Sales Price per ton sold$72.25 $61.33 $10.92 17.8%Average Costs per ton sold52.08 46.78 5.30 11.3%Margin$20.17 $14.55 $5.62 38.6%The higher average sales price per ton sold reflects successful re-negotiation of several domestic thermal contracts whose pricing took effect January 1,2011, another strong quarter of high volatile metallurgical coal sales and demand for our premium low volatile metallurgical coal. Also, 11.7 million tons werepriced on the export market at an average sales price of $121.29 per ton for the year ended December 31, 2011 compared to 8.1 million tons at an average priceof $97.10 per ton for the year ended December 31, 2010.Average costs per ton sold increased $5.30 per ton in the period-to-period comparison due primarily to the following:•Operating supplies and maintenance costs per ton sold were higher due to increased equipment overhauls, additional roof control and additionalequipment 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 perhour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related tothe July 2011 UMWA contract.•Other post employment benefits and pension expenses increased primarily due to changes in discount rates, employees retiring sooner thanoriginally anticipated and higher average claim costs.•Royalties and production related taxes increased due to higher sales price of coal sold.The total gas division includes coalbed methane (CBM), shallow oil and gas, Marcellus and other gas. The total gas division contributed $130 millionof earnings before income tax for the year ended December 31, 2011 compared to $180 million for the year ended December 31, 2010. Total gas productionwas 153.5 billion net cubic feet for the year ended December 31, 2011 compared to 127.9 billion net cubic feet for the year ended December 31, 2010. Totalgas production increased primarily due to the on-going drilling program partially offset by 6.6 billion net cubic feet of production related to the Noble jointventure.62The average sales price and average costs for all active gas operations were as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeAverage Sales Price per thousand cubic feet sold$4.90 $5.83 $(0.93) (16.0)%Average Costs per thousand cubic feet sold3.86 3.90 (0.04) (1.0)%Margin$1.04 $1.93 $(0.89) (46.1)%Total gas division outside sales revenues were $752 million for the year ended December 31, 2011 compared to $746 million for the year endedDecember 31, 2010. The increase was primarily due to 20.0% increase in volumes sold partially offset by the 16.0% reduction in average price per thousandcubic feet sold. The volume increase was primarily due to additional wells drilled under the on-going drilling program, and additional volumes from the wellspurchased in the Dominion Acquisition, which occurred on April 30, 2010 offset, in part, by the impact of the Noble joint venture which reduced 2011volumes by approximately 6.6 billion net cubic feet. The decrease in average sales price is the result of various gas swap transactions that occurred throughoutboth periods and lower average market prices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physicaltransactions. These financial hedges represented approximately 84.0 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2011at an average price of $5.21 per thousand cubic feet. These financial hedges represented 52.1 billion cubic feet of our produced gas sales volumes for the yearended December 31, 2010 at an average price of $7.66 per thousand cubic feet.Total gas unit costs decreased slightly for the year ended December 31, 2011 compared to the year ended December 31, 2010 primarily due to lowerdepreciation, depletion and amortization and lower gathering costs partially offset by increased lifting costs. The wells purchased in the Dominion Acquisitionincreased total operating costs by $0.32 per thousand cubic feet due to higher costs and lower volumes produced related to the age of these wells compared tothe legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.36 per thousand cubic feet primarily due to theadditional volumes produced, improved depreciation, depletion and amortization and lower gathering charges. Volumes increased in the period-to-periodcomparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition partially offset by theimpact of the Noble joint venture. Lower depreciation, depletion and amortization rates were the result of additional gas reserves recognized at December 31,2010. Gathering and compression charges were improved primarily due to a fuel surcharge reduction by a utility provider. Lifting costs increased in the period-to-period comparison due to additional well services to maintain production levels.The other segment includes industrial supplies activity, terminal, river and dock service activity, income taxes and other business activities not assignedto the coal or gas segment.Included in both coal and gas unit costs are Selling, General and Administrative Expenses and total Company long-term liabilities, such as other postemployment benefits (OPEB), the salary retirement plan, workers' compensation and long-term disability. Total Company Selling, General and AdministrativeExpenses are allocated to various segments primarily based on revenue and capital expenditure projections between coal and gas as a percent of total. TotalCompany Selling, General and Administrative Expenses were made up of the following items: For the Years Ended December 31, 2011 2010 Variance PercentChangeEmployee wages and related expenses$80 $72 $8 11.1%Demurrage6 2 4 200.0%Advertising and promotion10 7 3 42.9%Contributions7 4 3 75.0%Commissions14 12 2 16.7%Consulting and professional services28 26 2 7.7%Miscellaneous31 27 4 14.8%Total Company Selling, General and Administrative Expenses$176 $150 $26 17.3%63Total Company Selling, General and Administrative Expenses increased due to the following:•Employee wages and related expenses increased $8 million which was primarily attributable to the support staff retained in the Dominion Acquisitionand 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 individuallymaterial.•Commission expense increased $2 million due to the increase in average sales price and additional tons sold for which a third party was owed acommission 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 wereindividually 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.Total Company long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers' compensation and long-termdisability are actuarially calculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or activesalary dollars. Total CONSOL Energy expense related to our actuarial calculated liabilities was $332 million for the year ended December 31, 2011 comparedto $287 million for the year ended December 31, 2010. The increase of $45 million was due primarily to OPEB and salary pension expense. The additionalOPEB and salary pension expense related to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs.See Note 15—Pension and Other Postretirement Benefit Plans and Note 16—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in theNotes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-k for additional details related to total Company expense increases.64TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:The coal segment contributed $933 million of earnings before income tax in the year ended December 31, 2011 compared to $536 million in the yearended December 31, 2010. Variances by the individual coal segments are discussed below. For the Year Ended Difference to Year Ended December 31, 2011 December 31, 2010 ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoal ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoalSales: Produced Coal$3,058 $368 $1,072 $27 $4,525 $57 $196 $392 $15 $660Purchased Coal— — — 42 42 — — — 8 8Total Outside Sales3,058 368 1,072 69 4,567 57 196 392 23 668Freight Revenue— — — 232 232 — — — 106 106Other Income6 11 — 62 79 (2) 4 — 14 16Total Revenue and OtherIncome3,064 379 1,072 363 4,878 55 200 392 143 790Costs and Expenses: Total operating costs1,919 175 288 200 2,582 (15) 106 56 (7) 140Total provisions220 20 38 54 332 22 13 11 (74) (28)Total selling,administrative & othercosts167 18 28 87 300 25 13 10 (14) 34Depreciation, depletion andamortization302 31 37 130 500 28 20 16 78 142Total Costs and Expenses2,608 244 391 471 3,714 60 152 93 (17) 288Freight Expense— — — 231 231 — — — 105 105Total Costs2,608 244 391 702 3,945 60 152 93 88 393Earnings (Loss) Before IncomeTaxes$456 $135 $681 $(339) $933 $(5) $48 $299 $55 $39765THERMAL COAL SEGMENTThe thermal coal segment contributed $456 million to total Company earnings before income tax for the year ended December 31, 2011 compared to$461 million for the year ended December 31, 2010. The thermal coal revenue and cost components on a per unit basis for these periods are as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced Thermal Tons Sold (in millions)52.0 55.8 (3.8) (6.8)%Average Sales Price Per Thermal Ton Sold$58.87 $53.76 $5.11 9.5 %Average Operating Costs Per Thermal Ton Sold$36.93 $34.64 $2.29 6.6 %Average Provision Costs Per Thermal Ton Sold$4.24 $3.55 $0.69 19.4 %Average Selling, Administrative and Other Costs Per Thermal Ton Sold$3.21 $2.55 $0.66 25.9 %Average Depreciation, Depletion and Amortization Costs Per Thermal Ton Sold$5.81 $4.90 $0.91 18.6 % Total Average Costs Per Thermal Ton Sold$50.19 $45.64 $4.55 10.0 % Margin Per Thermal Ton Sold$8.68 $8.12 $0.56 6.9 %Thermal coal revenue was $3,058 million for the year ended December 31, 2011 compared to $3,001 million for the year ended December 31, 2010. The$57 million increase was attributable to a $5.11 per ton higher average sales price partially offset by 3.8 million fewer tons sold in 2011. The higher averagethermal coal sales price in the 2011 period was the result of the successful re-negotiation of several domestic thermal contracts whose pricing took effect onJanuary 1, 2011. Also, 2.8 million tons of thermal coal was priced on the export market at an average sales price of $66.45 per ton for the year endedDecember 31, 2011 compared to 2.4 million tons at an average price of $54.68 per ton for year ended December 31, 2010. The thermal coal segment was alsoimpacted by 4.7 million tons of thermal coal sold on the high volatile metallurgical coal market for the year ended December 31, 2011, which was 2.3 milliontons more than the tons sold in the year ended December 31, 2010.Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity in earningsof affiliates is insignificant to the total segment activity.Operating costs are comprised of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extractionand sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costsrelated to the thermal coal segment were $1,919 million for the year ended December 31, 2011 compared to $1,934 million for the year ended December31, 2010. Operating costs related to the thermal coal segment decreased primarily due to lower volumes sold partially offset by higher average costs per tonsold.Changes in the average operating costs per ton for thermal coal sold were also related to the following items:•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 additionalequipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roofbolts 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 ourcustomers. Increased fuel and lubricant costs are related to higher fuel prices in the current period.•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 weredue primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust werenegotiated under the National Bituminous Coal Wage Agreement and are based on a rate per hour worked by members of the United Mine Workers ofAmerica (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Non-represented benefitrates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due toadditional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under theprevious 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 expandingtransfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Planand 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 the66period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees.Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover thebenefits.•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 higherunit costs.Provision costs are made up of the expenses related to the Company's long-term liabilities, such as other post employment benefits (OPEB), the salaryretirement plan, workers' compensation, long-term disability and accretion on mine closing and related liabilities. With the exception of accretion expense onmine closing and related liabilities, these liabilities are actuarially calculated for the Company as a whole. The expenses are then allocated to operational unitsbased on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. Provision costs attributable to the thermal coalsegment were $220 million for the year ended December 31, 2011 compared to $198 million for the year ended December 31, 2010. The increased thermal coalprovision expense was attributable to the total Company increase in long-term liability expense discussed in the total Company results of operations section.Thermal coal accretion expense related to mine closing and related liabilities remained consistent in the period-to-period comparison.Selling, administrative and other costs attributable to the thermal coal segment include selling, general and administrative expenses and directadministrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to various segments based on a combination ofestimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling, is chargeddirectly to the mine incurring the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to variousmines based on a combination of estimated time worked and production. Selling, administrative and other costs related to the thermal coal segment were $167million for the year ended December 31, 2011 compared to $142 million for the year ended December 31, 2010. The cost increases attributable to the thermalcoal segment were attributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section and higherdirect administrative costs. Higher direct administrative costs were primarily due to higher employee related expenses due to additional support staffrequirements, increased safety reward expense and increased coal sampling charges in the period-to-period comparison. These higher costs and lower salesvolumes resulted in a $0.66 per ton increase in average cost per ton sold.Depreciation, depletion and amortization for the thermal coal segment was $302 million for the year ended December 31, 2011 compared to $274 millionfor the year ended December 31, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the 2010 period thatwas depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for thermal coal mines due to additional air shafts beingplaced into service after the 2010 period which had higher unit rates than historical shafts put into service. These higher expenses and lower sales tons,resulted in a $0.91 increase in average costs per ton sold.67HIGH VOL METALLURGICAL COAL SEGMENTThe high volatile metallurgical coal segment contributed $135 million to total Company earnings before income tax for the year ended December 31,2011 compared to $87 million for the year ended December 31, 2010. The high volatile metallurgical coal revenue and cost components on a per unit basis forthese periods are as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced High Vol Met Tons Sold (in millions)4.7 2.4 2.3 95.8%Average Sales Price Per High Vol Met Ton Sold$78.06 $72.89 $5.17 7.1%Average Operating Costs Per High Vol Met Ton Sold$37.18 $29.16 $8.02 27.5%Average Provision Costs Per High Vol Met Ton Sold$4.17 $3.08 $1.09 35.4%Average Selling, Administrative and Other Costs Per High Vol MetTon Sold$3.79 $2.26 $1.53 67.7%Average Depreciation, Depletion and Amortization Costs Per High VolMet Ton Sold$6.50 $4.61 $1.89 41.0% Total Average Costs Per High Vol Met Ton Sold$51.64 $39.11 $12.53 32.0% Margin Per High Vol Met Ton Sold$26.42 $33.78 $(7.36) (21.8%)High volatile metallurgical coal revenue was $368 million for the year ended December 31, 2011 compared to $172 million for the year ended December31, 2010. Strength in the metallurgical coal market has continued to allow the export of Northern Appalachian coal, historically sold domestically on thethermal coal market, to crossover to the Brazilian and Asian metallurgical coal markets. Also, 4.3 million tons of thermal coal was priced on the export marketat an average sales price of $77.48 per ton for the year ended December 31, 2011 compared to 2.3 million tons at an average price of $73.51 per ton for yearended December 31, 2010. As a result, average sales prices for high volatile metallurgical coal have increased due to growing the base of end user customers.Other income attributed to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatile metallurgicalcoal mines. The equity in earnings of affiliates is insignificant to the total segment activity.Operating costs related to the high volatile metallurgical coal segment were $175 million for the year ended December 31, 2011 compared to $69 millionfor the year ended December 31, 2010. Operating costs related to the high volatile metallurgical coal segment increased primarily due to higher volumes soldand higher average costs per ton sold.Changes in average operating costs per ton for high volatile metallurgical coal sold were primarily related to the following items:•Average operating costs per high volatile metallurgical ton sold increased due to the mix of mines selling coal on the high volatile metallurgical coalmarket. 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.•Labor and related benefits increased due to higher employee counts, higher non-represented benefit rates and higher contributions per hour worked tothe 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher laborand related costs were also due to higher non-represented benefit rates for active employees related to the continued increase in healthcare costs. Highercontributions made to the Trust were discussed in the thermal coal segment. Labor and related benefits also increased due to the impact of the wageincreases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement, in the period-to-period comparison. These increaseswere 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 additionalvolumes of high volatile metallurgical tons sold in the period-to-period comparison.•Average operating supplies and maintenance costs per high volatile metallurgical ton sold increased due to additional maintenance and equipmentoverhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related toadditional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as usinglonger 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 productionfor our customers.68•Average coal preparation costs per high vol ton sold increased due to additional maintenance projects that have been completed at our preparationplants 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 tothe preparation plant for processing. This increase is primarily related to the mix of mines now shipping high volatile metallurgical coal.The provision expense attributable to the high volatile metallurgical coal segment was $20 million for the year ended December 31, 2011 compared to $7million for the year ended December 31, 2010. The increase in the high volatile metallurgical coal provision expense was attributable to the total Companyincreased long-term liability expense discussed in the total Company results of operations section. The per unit impairment was offset, in part, by additionaltons sold in the period-to-period comparison. Also, high volatile metallurgical coal accretion expense related to mine closing and related liabilities remainedconsistent in the period-to-period comparison which offset some increases in costs per ton sold.Selling, administrative and other costs attributable to the high volatile metallurgical coal segment include selling, general and administrative expensesand direct administrative costs. Selling, general and administrative expenses, excluding commission expense, are allocated to various segments based on acombination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component ofselling, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal division of the business and areallocated to various mines based on a combination of estimated time worked and production. Selling, administrative and other costs related to the high volatilemetallurgical coal segment were $18 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. The costincrease attributable to the high volatile metallurgical coal segment is attributable to higher total Company selling, general and administrative expenses asdiscussed in the total Company results of operations section and higher direct administrative costs. Higher direct administrative costs were primarily due tohigher employee related expenses due to additional support staff requirements, increased safety reward expense and increased coal sampling charges in theperiod-to-period comparison. These additional expenses increased unit costs per ton sold and were offset, in part, by higher volumes of high volatilemetallurgical coal sold.Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $31 million for the year ended December 31, 2011 comparedto $11 million for the year ended December 31, 2010. The increase was primarily due to additional equipment and infrastructure placed into service after the2010 period that is depreciated on a straight-line basis. The increase was also due to higher units-of-production rates for high volatile metallurgical coal minesrelated to additional air shafts being placed into service after the 2010 period which had higher unit rates than historical shafts put into service. These increasesin unit costs per ton sold were offset, in part, by additional high volatile metallurgical tons sold which lowered the unit cost per ton impact. The high volatile metallurgical coal segment increased the margin on our coal production that would have otherwise been sold in the domestic thermal coalmarket. 69LOW VOL METALLURGICAL COAL SEGMENTThe low volatile metallurgical coal segment contributed $681 million to total Company earnings before income tax in the year ended December 31, 2011compared to $382 million in the year ended December 31, 2010. The low volatile metallurgical coal revenue and cost components on a per ton basis for theseperiods are as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced Low Vol Met Tons Sold (in millions)5.6 4.6 1.0 21.7%Average Sales Price Per Low Vol Met Ton Sold$191.81 $146.32 $45.49 31.1%Average Operating Costs Per Low Vol Met Ton Sold$51.57 $49.82 $1.75 3.5%Average Provision Costs Per Low Vol Met Ton Sold$6.84 $5.90 $0.94 15.9%Average Selling, Administrative and Other Costs Per Low Vol Met TonSold$4.97 $3.95 $1.02 25.8%Average Depreciation, Depletion and Amortization Costs Per Low VolMet Ton Sold$6.62 $4.57 $2.05 44.9% Total Average Costs Per Low Vol Met Ton Sold$70.00 $64.24 $5.76 9.0% Margin Per Low Vol Met Ton Sold$121.81 $82.08 $39.73 48.4%Low volatile metallurgical coal revenue was $1,072 million for the year ended December 31, 2011 compared to $680 million for the year endedDecember 31, 2010. The $392 million increase was attributable to a $45.49 per ton higher average sales price due to the strength of the low volatilemetallurgical market, both domestic and foreign. The strength of these markets is related to continued worldwide demand for premium low volatilemetallurgical coal. For the 2011 period, 4.6 million tons of low volatile metallurgical coal was priced on the export market at an average price of $196.46 perton compared to 3.3 million tons at an average price of $144.23 per ton for the 2010 period.Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income and preparation plant charges related to the extractionand sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costsrelated to the low volatile metallurgical coal segment were $288 million for the year ended December 31, 2011 compared to $232 million for the year endedDecember 31, 2010. Operating costs related to the low volatile metallurgical coal segment increased primarily due to higher volumes sold. Changes in the average operating costs per ton for low volatile metallurgical coal sold were primarily related to the following items:•Production taxes average cost per low volatile metallurgical ton sold increased due to the $45.49 per ton higher average sales price.•Average operating supplies and maintenance costs per low volatile metallurgical ton sold increased due to additional roof control costs, additionalventilation costs of coalbed methane gas, additional equipment overhaul costs and increased rock dusting. Additional roof control costs resulted fromchanges in roof support strategy, such as types of roof support used and quantity of supports put into place. The roof control strategy was changedto improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also increased due tohigher steel prices in the period-to-period comparison. In addition, costs were incurred in the 2011 period to increase the number of bore holes thatwere placed ahead of mining to ventilate the coalbed methane gas from the mine. Additional maintenance and equipment overhaul costs are related toadditional equipment being serviced in the current period. Increased rock dusting was primarily due to changes in regulations.These increases in costs were partially offset by the following items:•Coal inventory volumes increased slightly at December 31, 2011 compared to December 31, 2010 and carrying value increased $5.09 per ton in thecorresponding period. Coal inventory decreased 0.2 million tons at December 31, 2010 compared to December 31, 2009 and the carrying value of theinventory during the corresponding period increased $7.29 per ton. These changes in inventory caused a reduction in average operating cost per tonsold 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. The provision expense attributable to the low volatile metallurgical coal segment was $38 million for the year ended December 31, 2011 compared to $27million for the year ended December 31, 2010. The increased low volatile metallurgical70coal provision expense per ton sold was attributable to the total Company's increased long-term liability expense discussed in the total Company results ofoperations section, offset, in part, by higher volumes of low volatile metallurgical coal sold. Low volatile metallurgical coal accretion expense related to mineclosing and related liabilities decreased approximately $1 million in the period-to-period comparison as a result of the annual engineering surveys whichcontributed to lower average costs per ton sold.Selling, administrative and other costs attributable to the low volatile metallurgical coal segment include selling, general and administrative expenses,direct administrative costs and water treatment expenses generated from the reverse osmosis plant. Selling, general and administrative costs, excludingcommission expense and water treatment expense, are allocated to various segments on a combination of estimated time worked by various support groups andoperating costs incurred at the mine. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Directadministrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination of estimated timeworked and production. Selling, administrative and other costs related to the low volatile metallurgical coal segment were $28 million for the year endedDecember 31, 2011 compared to $18 million for the year ended December 31, 2010. The cost increase related to the low volatile metallurgical coal segment wasattributable to higher selling, general and administrative expenses as discussed in the total Company results of operations section. Also, a reverse osmosisplant was completed and placed into service near the Buchanan Mine. Active mine water discharge is being treated by this facility and the costs of theseservices are charged to the mine based on gallons of water treated. Currently, the Buchanan Mine is the only facility using the plant. Construction of the plantwas completed and the plant was placed into service in January 2011. These increases in expense were offset, in part, by higher volumes of low volatilemetallurgical coal sold. Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $37 million for the year ended December 31, 2011 comparedto $21 million for the year ended December 31, 2010. The increase was primarily due to additional equipment, infrastructure and the reverse osmosis plantplaced into service after the 2010 period that is depreciated on a straight-line basis. These increases in average costs per ton sold were offset, in part, by higherlow volatile metallurgical tons sold which lowered the unit cost per ton impact. OTHER COAL SEGMENTThe other coal segment had a loss before income tax of $339 million for the year ended December 31, 2011 compared to a loss before income tax of $394million for the year ended December 31, 2010. The other coal segment includes purchased coal activities, idle mine activities, as well as various activitiesassigned to the coal segment but not allocated to each individual mine.Other coal segment produced coal sales includes revenue from the sale of 0.4 million tons of coal which was recovered during the reclamation process atidled facilities for the year ended December 31, 2011 compared to 0.2 million tons for the year ended December 31, 2010. The primary focus of the activity atthese locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold are incidental tototal Company production or sales.Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coalspecifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants.The revenues were $42 million for the year ended December 31, 2011 compared to $34 million for the year ended December 31, 2010. The increase wasprimarily due to increased volumes sold partially offset by a decrease in the average sales price.Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freightrates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportationservices. Freight revenue is almost completely offset in freight expense. Freight revenue was $232 million for the year ended December 31, 2011 compared to$126 million for the year ended December 31, 2010. The increase in freight revenue was primarily due to the 3.6 million ton increase in export tons in theperiod-to-period comparison.Miscellaneous other income was $62 million for the year ended December 31, 2011 compared to $48 million for the year ended December 31, 2010. Theincrease of $14 million was primarily related to issuing pipeline right-of-ways to third parties which resulted in a gain of $12 million and various othertransactions that occurred throughout both periods, none of which were individually material.71Other coal segment total costs were $702 million for the year ended December 31, 2011 compared to $614 million for the year ended December 31, 2010.The increase of $88 million was due to the following items: For the Years Ended December 31, 2011 2010 VarianceAbandonment of long-lived assets $116 $— $116Freight expense 231 126 105Purchased Coal 71 40 31Coal contract buyout 5 — 5Closed and idle mines 107 222 (115)Litigation expense 8 55 (47)Other 164 171 (7) Total other coal segment costs $702 $614 $88•Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.•Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by thecustomers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers fortransportation costs incurred. Freight expense is almost completely offset in freight revenue. The increase was primarily due to the 3.6 million tonincrease 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 coalpurchased, 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 higherprice in a future period.•Closed and idle mine costs decreased approximately $115 million in the year ended December 31, 2011 compared to the year ended December31, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and the resulting changes in miningplans, the reclamation liability associated with the Fola mining operations in West Virginia increased $82 million. Also in the 2010 period, closedand 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, aportion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $9 million as a result of the decision topermanently abandon Mine 84. Closed and idle mine costs for the 2010 period also included $6 million related to various asset abandonments thatoccurred, none of which were individually material. In addition, $9 million of reduced expenses were recognized in closed and idle mine costs forvarious changes in the operational status of other mines, between idled and operating, throughout both periods, none of which were individuallymaterial. Closed and idle mine costs increased $5 million in the 2011 period due to a charge for an additional liability due to Pennsylvania streamremediation.•Litigation expense of $25 million was recognized in the year ended December 31, 2010 related to a legal settlement related to water discharge from ourBuchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was alsorecognized 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 itemswere individually material.•Other costs related to the coal segment decreased $7 million due to various other transactions that occurred throughout both periods, none of whichare individually material.72TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:The gas segment contributed $130 million to earnings before income tax for the year ended December 31, 2011 compared to $180 million for the yearended December 31, 2010. For the Year Ended Difference to Year Ended December 31, 2011 December 31, 2010 CBM Shallow Oiland Gas Marcellus OtherGas TotalGas CBM Shallow Oiland Gas Marcellus OtherGas TotalGasSales: Produced$461 $155 $119 $12 $747 $(106) $39 $70 $4 $7Related Party5 — — — 5 (1) — — — (1)Total Outside Sales466 155 119 12 752 (107) 39 70 4 6Gas Royalty Interest— — — 67 67 — — — 4 4Purchased Gas— — — 4 4 — — — (7) (7)Other Income— — — 59 59 — — — 54 54Total Revenue and OtherIncome466 155 119 142 882 (107) 39 70 55 57Lifting52 60 16 3 131 2 30 11 1 44Gathering98 27 15 2 142 1 9 5 (1) 14General & DirectAdministration61 30 17 4 112 (4) 8 9 6 19Depreciation,Depletion andAmortization101 61 35 10 207 (12) 11 15 3 17Gas Royalty Interest— — — 59 59 — — — 5 5Purchased Gas— — — 4 4 — — — (6) (6)Exploration and OtherCosts— — — 18 18 — — — (7) (7)Other CorporateExpenses— — — 65 65 — — — 9 9Interest Expense— — — 10 10 — — — 3 3Total Cost312 178 83 175 748 (13) 58 40 13 98Earnings BeforeNoncontrolling Interest andIncome Tax154 (23) 36 (33) 134 (94) (19) 30 42 (41)Noncontrolling Interest— — — 4 4 — — — 9 9Earnings Before IncomeTax$154 $(23) $36 $(37) $130 $(94) $(19) $30 $33 $(50)73COALBED METHANE (CBM) GAS SEGMENTThe CBM segment contributed $154 million to the total Company earnings before income tax for the year ended December 31, 2011 compared to $248million for the year ended December 31, 2010. For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced gas CBM sales volumes (in billion cubic feet)92.4 91.4 1.0 1.1 %Average CBM sales price per thousand cubic feet sold$5.05 $6.27 $(1.22) (19.5)%Average CBM lifting costs per thousand cubic feet sold$0.56 $0.54 $0.02 3.7 %Average CBM gathering costs per thousand cubic feet sold$1.06 $1.06 $— — %Average CBM general & direct administrative costs per thousandcubic feet sold$0.66 $0.70 $(0.04) (5.7)%Average CBM depreciation, depletion and amortization costs perthousand cubic feet sold$1.10 $1.25 $(0.15) (12.0)% Total Average CBM costs per thousand cubic feet sold$3.38 $3.55 $(0.17) (4.8)% Average Margin for CBM$1.67 $2.72 $(1.05) (38.6)%CBM sales revenues were $466 million for the year ended December 31, 2011 compared to $573 million for the year ended December 31, 2010. The$107 million decrease was primarily due to a 19.5% decrease in average sales price per thousand cubic feet sold, offset, in part, by a 1.1% increase in averagevolumes sold. The decrease in CBM average sales price is the result of various gas swap transactions that matured in each period and lower average marketprices. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedgesrepresented approximately 61.8 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2011 at an average price of $5.36per thousand cubic feet. For the year ended December 31, 2010, these financial hedges represented 50.5 billion cubic feet at an average price of $7.73 perthousand cubic feet. CBM sales volumes increased 1.0 billion cubic feet primarily due to additional wells coming on-line from our on-going drilling program.At December 31, 2011 and 2010 there were 4,262 and 4,020 CBM wells in production, respectively.Total costs for the CBM segment were $312 million for the year ended December 31, 2011 compared to $325 million for the year ended December31, 2010. Lower costs in the period-to-period comparison are primarily related to lower unit costs. CBM lifting costs were $52 million for the year ended December 31, 2011 compared to $50 million for the year ended December 31, 2010. Lifting costsincreased primarily due to increased road maintenance, additional tank repairs, and additional maintenance on older wells.CBM gathering costs were $98 million for the year ended December 31, 2011 compared to $97 million for the year ended December 31, 2010. CBMgathering unit costs remained consistent in the period-to-period comparison.General and direct administrative costs attributable to the total gas division were $112 million for the year ended December 31, 2011 compared to $93million for the year ended December 31, 2010. The $19 million increase was attributable to additional corporate service charges from CONSOL Energy andadditional staffing. Corporate service charge allocations are primarily based on revenue and capital expenditure projections between coal and gas as a percent oftotal. The additional staffing is primarily due to the majority of the operational support staff being retained from the Dominion Acquisition which closed onApril 30, 2010.General and direct administrative costs for the CBM segment were $61 million for year ended December 31, 2011 compared to $65 million for the yearended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individual gas segments based on acombination of production and employee counts. Lower general and direct administrative costs attributable to the CBM segment was attributable to the increasein other gas segment volumes.Depreciation, depletion and amortization attributable to the CBM segment was $101 million for the year ended December 31, 2011 compared to $113million for the year ended December 31, 2010. There was approximately $72 million, or $0.78 per unit-of-production, of depreciation, depletion andamortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31,2011. The production portion of depreciation, depletion and amortization was $87 million, or $0.98 per unit-of-production in the year ended December31, 2010. The CBM unit-of-production rate decreased due to revised rates which are generally calculated using the net book74value of assets divided by either proved or proved developed reserve additions. There was approximately $29 million, or $0.32 average per unit cost ofdepreciation, depletion and amortization relating to gathering and other equipment reflected on a straight line basis for the year ended December 31, 2011. Thenon-production related depreciation, depletion and amortization was $26 million, or $0.27 per thousand cubic feet for the year ended December 31, 2010. Theincrease was related to additional gathering assets placed in service after the 2010 period.SHALLOW OIL AND GAS SEGMENTThe shallow oil and gas segment had a loss before income tax of $23 million for the year ended December 31, 2011 compared to a loss before income taxof $4 million for the year ended December 31, 2010. For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced gas Shallow Oil and Gas sales volumes (in billion cubic feet)32.2 24.7 7.5 30.4 %Average Shallow Oil and Gas sales price per thousand cubic feet sold$4.83 $4.73 $0.10 2.1 %Average Shallow Oil and Gas lifting costs per thousand cubic feet sold$1.86 $1.24 $0.62 50.0 %Average Shallow Oil and Gas gathering costs per thousand cubic feet sold$0.83 $0.75 $0.08 10.7 %Average Shallow Oil and Gas general & direct administrative costs per thousandcubic feet sold$0.94 $0.88 $0.06 6.8 %Average Shallow Oil and Gas depreciation, depletion and amortization costs perthousand cubic feet sold$1.92 $2.03 $(0.11) (5.4)% Total Average Shallow Oil and Gas costs per thousand cubic feet sold$5.55 $4.90 $0.65 13.3 % Average Margin for Shallow Oil and Gas$(0.72) $(0.17) $(0.55) 323.5 %Shallow Oil and Gas sales revenues were $155 million for the year ended December 31, 2011 compared to $116 million for the year ended December31, 2010. The $39 million increase was primarily due to the 30.4% increase in volumes sold as well as the 2.1% increase in average sales price. Shallow Oiland Gas sales volumes increased 7.5 billion cubic feet in the year ended December 31, 2011 compared to the 2010 period primarily due to the DominionAcquisition, which closed on April 30, 2010. Approximately 95% of the acquired producing wells were Shallow Oil and Gas type wells. Average sales priceincreased primarily as the result of various gas swap transactions that matured in the year ended December 31 2011, offset, in part by lower average marketprices. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedgesrepresented approximately 11.5 billion cubic feet of our produced Shallow Oil and Gas gas sales volumes for the year ended December 31, 2011 at an averageprice of $4.97 per thousand cubic feet. There were no Shallow Oil and Gas gas swap transactions that occurred in the year ended December 31, 2010. Therewere 8,041 and 8,016 shallow oil and gas wells in production at December 31, 2011 and 2010, respectively.Shallow Oil and Gas lifting costs were $60 million for the year ended December 31, 2011 compared to $30 million for the year ended December 31,2010. Lifting costs per unit increased $0.62 per thousand cubic feet sold primarily due to increased road maintenance, increased well site maintenance,increased salt water disposal and additional well services performed to maintain production levels.Shallow Oil and Gas gathering costs were $27 million for the year ended December 31, 2011 compared to $18 million for the year ended December31, 2010. Average gathering costs increased $0.08 per unit primarily due to additional compressor maintenance.General and direct administrative costs for the Shallow Oil and Gas gas segment were $30 million for the year ended December 31, 2011 compared to$22 million for the year ended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individualgas segments based on a combination of production and employee counts. The total general and direct administrative costs increases which were discussed inthe CBM segment and higher volumes of Shallow Oil and Gas gas sold contributed to the increase in the Shallow Oil and Gas gas segment. General and directadministrative costs were $0.94 per thousand cubic feet sold for the year ended December 31, 2011 compared to $0.88 per thousand cubic feet sold for theyear ended December 31, 2010.Depreciation, depletion and amortization costs were $61 million for the year ended December 31, 2011 compared to $50 million for the year endedDecember 31, 2010. There was approximately $54 million, or $1.69 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oiland Gas gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2011. There wasapproximately $45 million, or75$1.84 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on aunits-of-production method of depreciation for the year ended December 31, 2010. The rate was calculated by taking the net book value of the related assetsdivided by either proved or proved developed reserves, generally at the previous year end. There was approximately $7 million, or $0.23 per thousand cubicfeet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the year ended December31, 2011. There was $5 million, or $0.19 per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipmentreflected on a straight line basis for the year ended December 31, 2010. The increase was related to additional infrastructure and equipment placed in serviceafter the 2010 period.MARCELLUS GAS SEGMENTThe Marcellus segment contributed $36 million to the total Company earnings before income tax for the year ended December 31, 2011 compared to $6million for the year ended December 31, 2010. For the Years Ended December 31, 2011 2010 Variance PercentChangeProduced gas Marcellus sales volumes (in billion cubic feet)26.9 10.4 16.5 158.7 %Average Marcellus sales price per thousand cubic feet sold$4.43 $4.69 $(0.26) (5.5)%Average Marcellus lifting costs per thousand cubic feet sold$0.60 $0.50 $0.10 20.0 %Average Marcellus gathering costs per thousand cubic feet sold$0.54 $0.99 $(0.45) (45.5)%Average Marcellus general & direct administrative costs perthousand cubic feet sold$0.64 $0.73 $(0.09) (12.3)%Average Marcellus depreciation, depletion and amortization costs perthousand cubic feet sold$1.32 $1.90 $(0.58) (30.5)% Total Average Marcellus costs per thousand cubic feet sold$3.10 $4.12 $(1.02) (24.8)% Average Margin for Marcellus$1.33 $0.57 $0.76 133.3 %The Marcellus segment sales revenues were $119 million for the year ended December 31, 2011 compared to $49 million for the year ended December31, 2010. The $70 million increase was primarily due to a 158.7% increase in average volumes sold, offset, in part, by a 5.5% decrease in average sales priceper thousand cubic feet sold. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program, partiallyoffset by 6.6 billion cubic feet related to the Noble joint venture and 1.0 billion cubic feet related to the Antero sale. The decrease in Marcellus average salesprice was the result of the decline in general market prices. These decreases were offset, in part, by various gas swap transactions that matured in the yearended December 31, 2011. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. Thesehedges represented approximately 10.6 billion cubic feet of our produced Marcellus gas sales volumes for the year ended December 31, 2011 at an averageprice of $4.64 per thousand cubic feet. For the year ended December 31, 2010, these financial hedges represented 1.6 billion cubic feet at an average price of$5.05 per thousand cubic feet. At December 31, 2011 and 2010, there were 110 and 52 gross Marcellus Shale wells in production, respectively.Marcellus lifting costs were $16 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. Liftingcosts per unit increased $0.10 per thousand cubic feet sold primarily due to increased expenses for well clean out and tubing replacement services performed toimprove production.Marcellus gathering costs were $15 million for the year ended December 31, 2011 compared to $10 million for the year ended December 31, 2010.Average gathering costs decreased $0.45 per unit primarily due to the 16.5 billion cubic feet of additional volumes sold.General and direct administrative costs for the Marcellus gas segment were $17 million for the year ended December 31, 2011 compared to $8 millionfor the year ended December 31, 2010. General and direct administrative costs attributable to the total gas segment are allocated to the individual gas segmentsbased on a combination of production and employee counts. The total general and direct administrative costs increases which were discussed in the CBMsegment and higher volumes of Marcellus gas sold contributed to the increase in the Marcellus gas segment. General and direct administrative costs were $0.64per thousand cubic feet sold for the year ended December 31, 2011 compared to $0.73 per thousand cubic feet sold for the year ended December 31, 2010.76Depreciation, depletion and amortization costs were $35 million for the year ended December 31, 2011 compared to $20 million for the year endedDecember 31, 2010. There was approximately $27 million, or $1.04 per unit-of-production, of depreciation, depletion and amortization related to Marcellusgas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2011. There wasapproximately $18 million, or $1.72 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipmentthat was reflected on a units-of-production method of depreciation for the year ended December 31, 2010. The rate was calculated by taking the net book valueof the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $8 million, or $0.28per thousand cubic feet, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for theyear ended December 31, 2011. There was $2 million, or $0.18 per thousand cubic feet, of depreciation, depletion and amortization related to gathering andother equipment reflected on a straight line basis for the year ended December 31, 2010. The increase was related to additional infrastructure and equipmentplaced in service after the 2010 period.OTHER GAS SEGMENTThe other gas segment includes activity not assigned to the CBM, conventional or Marcellus gas segments. This segment includes purchased gasactivity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific gassegment.Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately$12 million for the year ended December 31, 2011 and $8 million for the year ended December 31, 2010. Total costs related to these other sales were $19million for the 2011 period and were $10 million for the 2010 period. The increase in costs in the period-to-period comparison were primarily attributable toincreased general and direct administrative costs allocated to the other gas segment and increased depreciation, depletion and amortization. Higher general anddirect administrative costs were attributable to the total gas increase as discussed in the CBM segment coupled with increased sales volumes. Higherdepreciation, depletion and amortization was due to higher volumes produced and higher unit of production rates. A per unit analysis of the other operatingcosts in the Chattanooga shale is not meaningful due to the low volumes produced in the period-to-period analysis.Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energygas division. Royalty interest gas sales revenue was $67 million for the year ended December 31, 2011 compared to $63 million for the year ended December31, 2010. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royaltiescontributed to the period-to-period change. For the Years Ended December 31, 2011 2010 Variance PercentChangeGas Royalty Interest Sales Volumes (in billion cubic feet)16.414.2 2.2 15.5 %Average Sales Price Per thousand cubic feet$4.07$4.41 $(0.34) (7.7)%Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas salesrevenues were $4 million for the year ended December 31, 2011 compared to $11 million for the year ended December 31, 2010. For the Years Ended December 31, 2011 2010 Variance PercentChangePurchased Gas Sales Volumes (in billion cubic feet)1.02.0 (1.0) (50.0)%Average Sales Price Per thousand cubic feet$4.28$5.48 $(1.20) (21.9)%Other income was $59 million for the year ended December 31, 2011 compared to $5 million for the year ended December 31, 2010. The $54 millionincrease was primarily due to a gain on the Hess transaction of $53 million, a gain on the sale of the Antero overriding royalty interest of $41 million, $8million of additional interest income related to the notes receivable related to the Noble joint venture transaction, $5 million due to various transactions thatoccurred throughout both periods, none of which were individually material and $4 million due to increased earnings from equity affiliates. Theseimprovements were partially offset by a loss on the Noble transaction of $57 million.77Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gassegment. Royalty interest gas costs were $59 million for the year ended December 31, 2011 compared to $54 million for the year ended December31, 2010. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royaltiescontributed to the period-to-period change. For the Years Ended December 31, 2011 2010 Variance PercentChangeGas Royalty Interest Sales Volumes (in billion cubic feet)16.414.2 2.2 15.5 %Average Cost Per thousand cubic feet sold$3.61$3.78 $(0.17) (4.5)%Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact ofpipeline imbalances. The lower average cost per thousand cubic feet is due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $4 million for the year ended December 31, 2011 compared to $10 million for the year ended December 31,2010. For the Years Ended December 31, 2011 2010 Variance PercentChangePurchased Gas Volumes (in billion cubic feet)1.21.9 (0.7) (36.8)%Average Cost Per thousand cubic feet sold$3.07$5.14 $(2.07) (40.3)%Exploration and other costs were $18 million for the year ended December 31, 2011 compared to $25 million for the year ended December 31, 2010.The $7 million decrease in costs is primarily related to a favorable settlement involving defective pipe which reduced expense in the 2011 period and lower dryhole and lease surrender costs in the 2011 period. Costs included in the exploration and other cost line are detailed as follows: For the Years Ended December 31, 2011 2010 Variance PercentChangeDry hole and lease expiration costs$14 $21 $(7) (33.3)%Exploration4 4 — — %Total Exploration and Other Costs$18 $25 $(7) (28.0)%Other corporate expenses were $65 million for the year ended December 31, 2011 compared to $56 million for the year ended December 31, 2010. The$9 million increase in the period-to-period comparison was made up of the following items: For the Years Ended December 31, 2011 2010 Variance PercentChangeUnutilized firm transportation$14 $3 $11 366.7 %Contract buyout3 — 3 100.0 %Bank fees7 4 3 75.0 %Stock-based compensation18 16 2 12.5 %Short-term incentive compensation25 24 1 4.2 %Variable interest earnings(4) 4 (8) (200.0)%Legal fees— 3 (3) (100.0)%Other2 2 — — %Total Other Corporate Expenses$65 $56 $9 16.1 %•Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flowuninterrupted 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 facility78related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.•Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a resultof the Dominion Acquisition as well as an increase in total CONSOL Energy stock-based compensation expense. Stock-based compensation costsare allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.•The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predeterminedtargets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result ofexceeding the targets in the 2011 period, increased number of employees, and an increased allocation of expense from CONSOL Energy as the resultof exceeding corporate targets.•Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds noownership interest and during the 2011 period de-consolidated the impact of this third party due to the cancellation of the drilling arrangement. Basedon analysis, during the time CONSOL Energy guaranteed the bank loans the entity held, it was determined that CONOL Energy was the primarybeneficiary. Therefore, the entity was fully consolidated and the earnings impact was fully reversed in the non-controlling interest line discussedbelow.•Legal fees for the 2010 period were related to the special committee formed during the CNX Gas take-in transaction and also represent legal feesrelated to the shareholder litigation related to this transaction.•Other corporate related expense remained consistent in the period-to-period comparison.Interest expense related to the other gas segment was $10 million for the year ended December 31, 2011 compared to $7 million for the year endedDecember 31, 2010. Interest was incurred by the other gas segment on the CNX Gas revolving credit facility, a capital lease and debt held by a variable interestentity. The $3 million increase was primarily due to higher levels of borrowings on the revolving credit facility in the period-to-period comparison.Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in whichCONSOL Energy held no ownership interest, but was the primary beneficiary. The CONSOL Energy gas division was determined to be the primarybeneficiary due to guarantees of the third party's bank debt related to their purchase of drilling rigs. The third-party entity provides drilling services primarilyto the CONSOL Energy gas division. CONSOL Energy consolidates the entity and then reflects 100% of the impact as noncontrolling interest. Theconsolidation did not significantly impact any amounts reflected in the gas division income statement. The variance in the noncontrolling amounts reflects thethird party's variance in earnings in the period-to-period comparison. In the year ended December 31, 2011, the drilling services contract was bought out.Subsequent to this transaction, the noncontrolling interest was de-consolidated.79OTHER SEGMENT ANALYSIS for the year ended December 31, 2011 compared to the year ended December 31, 2010:The other segment includes activity from the sales of industrial supplies, the transportation operations and various other corporate activities that are notallocated to the coal or gas segment. The other segment had a loss before income tax of $275 million for the year ended December 31, 2011 compared to a lossbefore income tax of $249 million for the year ended December 31, 2010. The other segment also includes total company income tax expense of $155 millionfor the year ended December 31, 2011 compared to $109 million for the year ended December 31, 2010. For the Years Ended December 31, 2011 2010 Variance PercentChangeSales—Outside$346 $297 $49 16.5 %Other Income16 29 (13) (44.8)%Total Revenue362 326 36 11.0 %Cost of Goods Sold and Other Charges368 349 19 5.4 %Depreciation, Depletion & Amortization19 18 1 5.6 %Taxes Other Than Income Tax11 10 1 10.0 %Interest Expense239 198 41 20.7 %Total Costs637 575 62 10.8 %Loss Before Income Tax(275) (249) (26) (10.4)%Income Tax155 109 46 42.2 %Net Loss$(430) $(358) $(72) (20.1)%Industrial supplies:Total revenue from industrial supplies was $236 million for the year ended December 31, 2011 compared to $195 million for the year endedDecember 31, 2010. The increase was related to higher sales volumes.Total costs related to industrial supply sales were $235 million for the year ended December 31, 2011 compared to $197 million for the year endedDecember 31, 2010. The increase of $38 million was primarily related to higher sales volumes and changes in last-in, first-out inventory valuations.Transportation operations:Total revenue from transportation operations was $120 million for the year ended December 31, 2011 compared to $114 million for the year endedDecember 31, 2010. The increase of $6 million was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-periodcomparison.Total costs related to the transportation operations were $89 million for the year ended December 31, 2011 compared to $81 million for the year endedDecember 31, 2010. The increase of $8 million was related to the additional through-put tons handled by the operations and additional repairs andmaintenance costs to maintain the Baltimore terminal facilities.Miscellaneous other:Additional other income of $6 million was recognized for the year ended December 31, 2011 compared to $17 million for the year ended December 31,2010. The $11 million decrease was primarily due to $5 million related to the 2010 successful resolution of an outstanding tax issue with the CanadianRevenue Authority for the years 1997 through 2003 in which CONSOL Energy was entitled to interest on a tax refund, $2 million lower equity in earnings ofaffiliates in the current period compared to the prior year period and $4 million related to various transactions that have occurred throughout both periods,none of which were individually material.Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges.Total other costs were $313 million for the year ended December 31, 2011 compared to $297 million for the year ended December 31, 2010. Other corporatecosts increased due to the following items:80 For the Years Ended December 31, 2011 2010 VarianceInterest expense $239 $198 $41Loss on extinguishment of debt 16 — 16Evaluation fees for non-core asset dispositions 6 2 4Bank fees 18 16 2Transaction and financing fees 15 61 (46)Other 19 20 (1) $313 $297 $16•Interest expense increased $41 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the DominionAcquisition in April 2010.•On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordancewith the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, whichprimarily 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 beganin 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.•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, aswell 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.Income Taxes:The effective income tax rate was 19.7% for the year ended December 31, 2011 compared to 23.4% for the year ended December 31, 2010. The decreasein the effective tax rate for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily attributable to various discretetransactions that occurred in both periods. The discrete transactions included an Internal Revenue Service audit settlement for years 2006 and 2007 and thecorresponding impacts to the previously accrued tax positions which resulted in higher percentage depletion deductions. Discrete transactions also included thereversal of a valuation allowance for certain state net operating loss carryforwards and future temporary deductions as well as the reversal of certain uncertaintax positions. See Note 6—Income Taxes of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additionalinformation. For the Years Ended December 31, 2011 2010 Variance PercentChangeTotal Company Earnings Before Income Tax$788 $468 $320 68.4%Income Tax Expense$155 $109 $46 42.2%Effective Income Tax Rate19.7% 23.4% (3.7)% 81Results of OperationsYear Ended December 31, 2010 Compared with the Year Ended December 31, 2009Net Income Attributable to CONSOL Energy ShareholdersCONSOL Energy reported net income attributable to CONSOL Energy shareholders of $347 million, or $1.60 per diluted share, for the year endedDecember 31, 2010. Net income attributable to CONSOL Energy shareholders was $540 million, or $2.95 per diluted share, for the year ended December 31,2009. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.The total coal segment includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal segmentcontributed $536 million of earnings before income tax for the year ended December 31, 2010 compared to $546 million for the year ended December 31,2009. The total coal segment sold 63.0 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates,in the year ended December 31, 2010 compared to 57.4 million tons in the year ended December 31, 2009. The average sales price and total costs per ton for allactive coal operations were as follows: Year Ended December 31, 2010 2009 Variance PercentChangeAverage Sales Price per ton sold$61.33 $58.70 $2.63 4.5%Average Costs per ton sold46.78 44.66 2.12 4.7%Margin$14.55 $14.04 $0.51 3.6%The higher average sales price per ton sold reflects an additional 2.3 million tons of low volatile metallurgical coal and 2.4 million tons of high volatilemetallurgical coal sold in 2010 compared to 2009. The low volatile metallurgical coal segment also had a higher average sales price in 2010 compared to 2009reflecting the strengthening of the global steel market and steel related products. The high volatile metallurgical coal global market allowed approximately2.4 million tons of coal to be sold as a metallurgical product at an average sales price of $72.89 per ton. This coal historically would have been sold on thethermal market where our average price for 2010 was $53.76 per ton.Average costs per ton of coal sold have increased in the period-to-period comparison due primarily to additional labor, higher supply and maintenancecosts, and increased other costs which are directly related to the higher sales prices received for tons sold. Additional labor costs per ton are related to the netaddition of approximately 330 employees. The additional labor was attributed to the Shoemaker Mine resuming production in 2010 after being idled throughout2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional labor was also added in order to run our minesmore 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 thelongwall panels ahead of longwall advancement. Additional supply costs were attributable to compliance with new safety regulations such as fire retardantbelts, additional equipment maintenance and various changes in roof control measures. Costs directly related to the price received for coal sales have alsoincreased. These costs include royalty expenses and various production taxes.The total gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. The total gas segment contributed $180 million ofearnings before income tax for the year ended December 31, 2010 compared to $263 million for the year ended December 31, 2009. Total gas production was127.9 billion cubic feet for the year ended December 31, 2010 compared to 94.4 billion cubic feet for the year ended December 31, 2009.The average sales price and total costs for all active gas operations were as follows: Year Ended December 31, 2010 2009 Variance PercentChangeAverage Sales Price per thousand cubic feet sold$5.83 $6.68 $(0.85) (12.7)%Average Costs per thousand cubic feet sold3.90 3.44 0.46 13.4 %Margin$1.93 $3.24 $(1.31) (40.4)%Total gas segment outside sales revenues were $746 million for the year ended December 31, 2010 compared to $630 million for the year endedDecember 31, 2009. The increase was primarily due to the 35.5% increase in volumes sold, offset, in part, by82the 12.7% reduction in average price per thousand cubic feet sold. The decrease in average sales price is the result of various gas swap transactions thatoccurred throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physicaltransactions. These financial hedges represented approximately 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31,2010 at an average price of $7.66 per thousand cubic feet. These financial hedges represented approximately 51.6 billion cubic feet of our produced gas salesvolumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. Average gas sales prices excluding the impact of hedgingwere up slightly in the period-to-period comparison.Total gas unit costs increased for the year ended December 31, 2010 compared to the year ended December 31, 2009 primarily due to the impact of thehigher cost structure of the producing wells purchased in the Dominion Acquisition. These wells increased total operating costs by $0.78 per thousand cubicfeet due to the higher maintenance costs, higher gathering and transportation costs and lower volumes produced compared to the legacy CONSOL Energywells. Excluding the impact of these purchased wells, unit costs improved $0.32 per thousand cubic feet primarily due to the additional volumes produced.Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in theDominion Acquisition.The other segment includes industrial supplies activity, terminal and river service activity, income taxes and other business activities not assigned to thecoal or gas segment.TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:The coal segment contributed $536 million of earnings before income tax in the year ended December 31, 2010 compared to $546 million in the yearended December 31, 2009. Variances by the individual coal segments are discussed below. For the Year Ended Difference to Year Ended December 31, 2010 December 31, 2009 SteamCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoal SteamCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoalSales: Produced Coal$3,001 $172 $680 $12 $3,865 $(121) $172 $431 $12 $494Purchased Coal— — — 34 34 — — — (5) (5)Total Outside Sales3,001 172 680 46 3,899 (121) 172 431 7 489Freight Revenue— — — 126 126 — — — (23) (23)Other Income8 7 — 48 63 1 7 — (22) (14)Total Revenue and OtherIncome3,009 179 680 220 4,088 (120) 179 431 (38) 452Costs and Expenses: Total operating costs1,934 69 232 207 2,442 106 69 116 (9) 282Total provisions198 7 27 128 360 18 7 11 100 136Total selling,administrative & other costs142 5 18 101 266 (2) 5 8 2 13Depreciation, depletion andamortization274 11 21 52 358 16 11 8 19 54Total Costs and Expenses2,548 92 298 488 3,426 138 92 143 112 485Freight Expense— — — 126 126 — — — (23) (23)Total Costs2,548 92 298 614 3,552 138 92 143 89 462Earnings (Loss) Before IncomeTaxes$461 $87 $382 $(394) $536 $(258) $87 $288 $(127) $(10)83THERMAL COAL SEGMENT:The thermal coal segment contributed $461 million to total company earnings before income tax in the year ended December 31, 2010 compared to $719million in the year ended December 31, 2009. The thermal coal revenue and cost components on a per unit basis are as follows: For the Year Ended December 31, 2010 2009 Variance PercentChangeProduced Thermal Tons Sold (in millions)55.8 55.1 0.7 1.3 %Average Sales Price Per Thermal Ton Sold$53.76 $56.64 $(2.88) (5.1)%Average Operating Costs Per Thermal Ton Sold$34.64 $33.16 $1.48 4.5 %Average Provision Costs Per Thermal Ton Sold$3.55 $3.27 $0.28 8.6 %Average Selling, Administrative and Other Costs Per Thermal Ton Sold$2.55 $2.60 $(0.05) (1.9)%Average Depreciation, Depletion and Amortization Costs Per Thermal Ton Sold$4.90 $4.68 $0.22 4.7 % Total Average Costs Per Thermal Ton Sold$45.64 $43.71 $1.93 4.4 % Margin Per Thermal Ton Sold$8.12 $12.93 $(4.81) (37.2)%Thermal coal revenue was $3,001 million for the year ended December 31, 2010 compared to $3,122 million for the year ended December 31, 2009. The$121 million decrease was attributable to an average sales price reduction of $2.88 per ton partially offset by a 0.7 million increase in tons sold. Thermal coalaverage sales price is lower in the 2010 period compared to the 2009 period as a result of higher average sales price mines, such as Bailey and Enlow Fork,selling coal in the high volatile metallurgical coal market instead of the thermal coal market. This impacted the thermal coal segment as a result of leaving moretons sold from lower sales price mines. This has negatively impacted the average sales price on the thermal coal segment, although total company revenue hasimproved. Produced thermal inventory was 1.9 million tons at December 31, 2010 compared to 2.9 million tons at December 31, 2009. Thermal sales tonswere higher in the period-to-period comparison primarily due to the Shoemaker Mine restarting production in early 2010 after being idled throughout 2009 tocomplete the replacement of the track haulage system. Thermal sales tons were also higher as the result of the Blacksville #2 Mine being idled for severalmonths in 2009 in order to manage inventory levels in response to the economic crisis experienced. Blacksville #2 Mine has operated throughout 2010. Theseincreases were offset, in part, due to selling 2.4 million tons on the high volatile metallurgical coal market at approximately $19.13 per ton higher average salesprice.Other income attributable to the thermal coal segment represents earnings from our equity affiliate that operates a thermal coal mine. The equity inearnings of affiliates is insignificant to the total segment activity.Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income, royalties and preparation plant charges related to theextraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operatingcosts related to the thermal coal segment were $1,934 million for the year ended December 31, 2010 compared to $1,828 million for the year endedDecember 31, 2009. Higher operating costs in the period-to-period comparison are due to the $1.48 per ton increase in average unit costs of tons sold and0.7 million of additional tons sold.Higher average operating costs per unit for thermal coal tons sold are primarily related to the following items:•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 volatilemetallurgical coal market. This impacted the thermal coal segment due to increased tons sold from higher cost mines.•Labor costs increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specifiedhourly 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 theShoemaker Mine resuming production in 2010 after being idled during 2009 to complete the replacement of the track haulage system to a moreefficient belt haulage system. Additional employees were also added in order to run our mines more safely, to prepare for the expected retirement ofa significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwalladvancement.•Health and retirement costs related to the active hourly work force increased due to higher contributions to the multiemployer 1974 pension trustthat are required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by membersof the United Mine Workers Union of America84(UMWA) in the year ended December 31, 2009 to $5.00 per hour worked in the year ended December 31, 2010. Contributions to themultiemployer plan are expensed as incurred. Health and Retirement costs have also increased in the period-to-period comparison due to highermedical costs for the active hourly work force.•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.The increases in average unit costs of thermal coal sold were offset, in part, by the following:•Reduced contract mining fees due to fewer contractors being retained to mine our reserves in the year ended December 31, 2010 compared to the2009 period.•Average operating costs per thermal ton sold decreased due to higher tons sold. Fixed costs are allocated over higher tons resulting in decreased unitcosts.Total CONSOL Energy expenses related to our actuarial liabilities were $287 million for the year ended December 31, 2010 compared to $243 millionfor the year ended December 31, 2009. The increase of $44 million was due primarily to changes in the discount rates used at the measurement date, which isDecember 31, and changes in assumptions which affect the amount of actuarial gains and losses amortized into earnings. See Note 15-Pension and OtherPostretirement Benefits Plans and Note 16-Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited ConsolidatedFinancial Statements in Item 8 of this Form 10-K for additional detail regarding total company expense.Total provisions are made up of the expenses related to the Company's long-term liabilities, such as other post employment benefits (OPEB), the salaryretirement plan, workers' compensation, long-term disability and accretion expense on mine closing and related liabilities. With the exception of accretionexpense on mine closing and related liabilities, these expenses are actuarially calculated for the company as a whole. The expenses are then allocated tooperational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. Provisions attributable to thethermal coal segment were $198 million for the year ended December 31, 2010 compared to $180 million for the year ended December 31, 2009. Provisioncosts per thermal coal ton sold increased $0.28 per ton in the period-to-period comparison due primarily to higher actuarial expenses, such as OPEB, asdiscussed above. The overall increase in company costs has increased the total dollars allocated to the thermal coal segment. This increase was offset, in part,by additional tons sold by the thermal coal segment.Total Company Selling, General and Administrative Expenses were made up of the following items: For the Year Ended December 31, 2010 2009 Variance PercentChangeEmployee wages and related expenses$72 $63 $9 14.3%Commissions12 7 5 71.4%Miscellaneous66 61 5 8.2%Total Company Selling, General and Administrative Expenses$150 $131 $19 14.5%•Employee wages and related expenses have increased due to additional employees in the selling, general and administrative area primarily relatedto support staff retained in the Dominion Acquisition which occurred on April 30, 2010 and additional hiring to support operations. Increasedemployee 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 yearperiod.•Miscellaneous expenses have increased approximately $5 million. The increase was related to an additional $2 million for advertising andpromotion fees, an additional $2 million for demurrage charges and an additional $1 million for various other items, none of which wereindividually material.Total administrative and other costs related to the thermal coal segment were $142 million for the year ended December 31, 2010 and $144 million for theyear ended December 31, 2009. Selling, general and administrative costs, excluding selling expense, are allocated to all segments based on a combination ofestimated time worked by various support groups and operating costs incurred by the individual segments. Commission expense, which is a component ofselling, is charged directly to the mine incurring85the cost. Direct administrative costs are associated directly with the coal division of the business and are allocated to various mines based on a combination ofestimated time worked and production. Although the total company selling, general and administrative costs have increased, as discussed above, the amountallocated to the thermal coal segment has decreased approximately $2 million. The decrease in the amount allocated to the thermal coal segment is primarilyrelated to the high volatile metallurgical coal segment. In 2009, these tons and the associated allocation were all included in the thermal coal segment.Depreciation, depletion and amortization costs for the thermal coal segment were $274 million for the year ended December 31, 2010 and $258 millionfor the year ended December 31, 2009. The increase of $16 million, or $0.22 per ton, was due to additional equipment and infrastructure placed into serviceafter 2009, offset, in part, by additional volumes sold.HIGH VOL METALLURGICAL COAL SEGMENT:The high volatile metallurgical coal segment contributed $87 million to total company earnings before income tax for the year ended December 31, 2010.There was no activity in this segment in the prior year. This is a new market that was developed in 2010 and is primarily related to selling our Pittsburgh #8coal into overseas metallurgical coal markets. This coal had historically supplied the domestic thermal coal market. The high volatile metallurgical coalrevenue and cost components on a per unit basis are as follows: For the Year Ended December 31, 2010 2009 Variance PercentChangeProduced High Vol Met Tons Sold (in millions)2.4 — 2.4 100.0%Average Sales Price Per High Vol Met Ton Sold$72.89 $— $72.89 100.0%Average Operating Costs Per High Vol Met Ton Sold$29.16 $— $29.16 100.0%Average Provision Costs Per High Vol Met Ton Sold$3.08 $— $3.08 100.0%Average Selling, Administrative and Other Costs Per High Vol MetTon Sold$2.26 $— $2.26 100.0%Average Depreciation, Depletion and Amortization Costs Per High VolMet Ton Sold$4.61 $— $4.61 100.0% Total Average Costs Per High Vol Met Ton Sold$39.11 $— $39.11 100.0% Margin Per High Vol Met Ton Sold$33.78 $— $33.78 100.0%The high volatile metallurgical coal segment revenue was $172 million, or an average sales price per ton of $72.89, for the year ended December 31,2010. Strength in the metallurgical coal market allowed for the export of Northern Appalachian coal, historically sold domestically on the thermal coal market,to crossover to the metallurgical coal markets in Brazil and Asia. Total costs per ton sold of this coal were $39.11 generating a margin of $33.78 per ton sold.This margin exceeds the $8.12 per ton average margin received on thermal coal sold in 2010 which is where this coal would have been historically sold.Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate mines that sell coal onthe high volatile metallurgical coal market. The equity in earnings of affiliates is insignificant to the total segment activity.86LOW VOL METALLURGICAL COAL SEGMENT:The low volatile metallurgical coal segment contributed $382 million to total company earnings before income tax for the year ended December 31, 2010compared to $94 million for the year ended December 31, 2009. The increase was due primarily to the Buchanan Mine being idled for approximately fivemonths of 2009. The mine was idled in 2009 in response to the economic crisis which significantly lowered the demand for low volatile metallurgical coal,primarily due to the decrease in steel demand. The Buchanan Mine has operated throughout all of 2010. The low volatile metallurgical coal revenue and costcomponents on a per unit basis are as follows: For the Year Ended December 31, 2010 2009 Variance PercentChangeProduced Low Vol Met Tons Sold (in millions)4.6 2.3 2.3 100.0 %Average Sales Price Per Low Vol Met Ton Sold$146.32 $107.72 $38.60 35.8 %Average Operating Costs Per Low Vol Met Ton Sold$49.82 $50.33 $(0.51) (1.0%)Average Provision Costs Per Low Vol Met Ton Sold$5.90 $6.76 $(0.86) (12.7)%Average Selling, Administrative and Other Costs Per Low Vol Met TonSold$3.95 $4.57 $(0.62) (13.6)%Average Depreciation, Depletion and Amortization Costs Per Low VolMet Ton Sold$4.57 $5.46 $(0.89) (16.3)% Total Average Costs Per Low Vol Met Ton Sold$64.24 $67.12 $(2.88) (4.3)% Margin Per Low Vol Met Ton Sold$82.08 $40.60 $41.48 102.2 %Average sales price for low volatile metallurgical coal has increased $38.60 per ton, from the prior year, to $146.32 for the year ended December 31,2010. The increase of 35.8% was mainly due to the strengthening of the global market for steel and steel related products when compared to 2009.Total costs per ton sold of low volatile metallurgical coal were $64.24 per ton for the year ended December 31, 2010 compared to $67.12 per ton for theyear ended December 31, 2009. The $2.88 per ton improvement was related to operating the Buchanan Mine for all of 2010 versus seven months of 2009. Theadditional tonnage sold in 2010 has reduced the average per unit costs.OTHER COAL SEGMENT:The Other Coal segment had a loss before income tax of $394 million for the year ended December 31, 2010 compared to a loss before income tax of$267 million for the year ended December 31, 2009. The Other Coal segment includes purchased coal activities, idled mine activities as well as various otheractivities assigned to the coal segment but not allocated to each individual mine.Other Coal segment produced coal sales revenue was $12 million for the year ended December 31, 2010. This revenue includes the sale of incidentaltonnage recovered during the reclamation process at idled facilities. The primary focus of activity at these locations is reclaiming disturbed land in accordancewith permit requirements after final mining has occurred. The tons sold from these activities are incidental to total company production and sales.Purchased coal sales were $34 million for the year ended December 31, 2010 compared to $39 million for the year ended December 31, 2009. Purchasedcoal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coalpurchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants for a fee.Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped, negotiated freightrates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportationservices. Freight revenue is offset in freight expense. Freight revenue was $126 million in the year ended December 31, 2010 compared to $149 million for theyear ended December 31, 2009. The decrease of $23 million was primarily due to lower tons being shipped on CONSOL Energy freight contracts in theperiod-to-period comparison.87Miscellaneous other income was $48 million for the year ended December 31, 2010 compared to $70 million for the year ended December 31, 2009. The$22 million decrease was due to the following items:•In the year ended December 31, 2009, $12 million of income was recognized related to contracts with certain customers that were unable to takedelivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from the requirements oftaking 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 forthe year ended December 31, 2009. The change was related to various transactions that occurred throughout both periods, none of which wereindividually material.•Coal royalty income from third parties was $15 million for the year ended December 31, 2010 compared to $17 million for the year endedDecember 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 millionreversal of previously recognized unrealized losses. The reversal of the losses was primarily due to the decrease in market price of coal in 2009compared 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.Other coal segment total costs were $614 million for the year ended December 31, 2010 compared to $525 million for the year ended December 31,2009. The increase of $89 million was due to the following items:•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 Folamining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mineplans, the reclamation liability associated with the Fola operation increased approximately $81 million. Additional closed and idle mine costs in2010 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 ofthe previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $18 million for changes inthe operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in2010. Shoemaker Mine was idled throughout 2009 while the track haulage system was converted to a belt haulage system. This mine was inproduction 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. Thelitigation was related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased byCONSOL Energy subsidiaries.•Cost of goods sold and other charges have increased approximately $13 million related to excess purchase price over appraised values for variousland 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 asrefuse ponds, overland belts and various other key projects often require premiums over fair value, thus resulting in additional expense toCONSOL 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 MiningComplex.•Cost of goods sold and other charges have increased approximately $8 million due to various asset abandonments throughout the period, none ofwhich were individually material. These abandonments primarily related to engineering work, permitting work and mapping work formiscellaneous projects that are no longer being pursued by the Company.•Purchased coal consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coalspecifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. These costswere $40 million for the year ended December 31, 2010 compared to $46 million for the year ended December 31, 2009. The decrease of $6million 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 LevisaAction and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.88•Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by thecustomers to which CONSOL Energy contractually provides transportation services. Freight expense is offset in freight revenue. Freight expensewas $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23million 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 othertransactions that have occurred throughout both periods, none of which are individually material.TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:The gas segment contributed $180 million to earnings before income tax for the year ended December 31, 2010 compared to $263 million for the yearended December 31, 2009. Variances by the individual gas segments are discussed below. For the Year Ended Difference to Year Ended December 31, 2010 December 31, 2009 CBM Shallow Oiland Gas Marcellus OtherGas TotalGas CBM Shallow Oiland Gas Marcellus OtherGas TotalGasSales: Produced$567 $116 $49 $8 $740 $(27) $108 $28 $4 $113Related Party6 — — — 6 3 — — — 3Total Outside Sales573 116 49 8 746 (24) 108 28 4 116Gas Royalty Interest— — — 63 63 — — — 22 22Purchased Gas— — — 11 11 — — — 4 4Other Income— — — 5 5 — — — — —Total Revenue and OtherIncome573 116 49 87 825 (24) 108 28 30 142Lifting50 30 5 2 87 1 26 4 1 32Gathering97 18 10 3 128 9 17 5 1 32General & DirectAdministration65 22 8 (2) 93 3 21 4 (2) 26Depreciation,Depletion andAmortization113 50 20 7 190 19 46 13 5 83Gas Royalty Interest— — — 54 54 — — — 22 22Purchased Gas— — — 10 10 — — — 4 4Exploration andOther Costs— — — 25 25 — — — 8 8Other CorporateExpenses— — — 56 56 — — — 23 23Interest Expense— — — 7 7 — — — (1) (1)Total Cost325 120 43 162 650 32 110 26 61 229Earnings BeforeNoncontrolling Interest andIncome Tax248 (4) 6 (75) 175 (56) (2) 2 (31) (87)Noncontrolling Interest— — — (5) (5) — — — (4) (4)Earnings Before IncomeTax$248 $(4) $6 $(70) $180 $(56) $(2) $2 $(27) $(83)89COALBED METHANE (CBM) GAS SEGMENT:The CBM segment contributed $248 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $304million for the year ended December 31, 2009. The CBM segment revenue and cost components on a per unit basis were as follows: For the Years Ended December 31, 2010 2009 Variance PercentChangeProduced gas CBM sales volumes (in billion cubic feet)91.4 86.9 4.5 5.2 %Average CBM sales price per thousand cubic feet sold$6.27 $6.87 $(0.60) (8.7)%Average CBM lifting costs per thousand cubic feet sold$0.54 $0.57 $(0.03) (5.3)%Average CBM gathering costs per thousand cubic feet sold$1.06 $1.01 $0.05 5.0 %Average CBM general & direct administrative costs per thousandcubic feet sold$0.70 $0.71 $(0.01) (1.4)%Average CBM depreciation, depletion and amortization costs perthousand cubic feet sold$1.25 $1.08 $0.17 15.7 % Total Average CBM costs per thousand cubic feet sold$3.55 $3.37 $0.18 5.3 % Average Margin for CBM$2.72 $3.50 $(0.78) (22.3)%CBM sales revenues were $573 million for the year ended December 31, 2010 compared to $597 million for the year ended December 31, 2009. Thedecrease was primarily due to the 8.7% reduction in average price per thousand cubic feet sold, offset, in part, by the 5.2% increase in volumes sold. Thedecrease in CBM average sales price was the result of various gas swap transactions at a lower average price as compared to the prior year. These gas swaptransactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately50.5 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2010 at an average price of $7.73 per thousand cubic feet.These financial hedges represented approximately 51.6 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2009 at anaverage price of $8.76 per thousand cubic feet. Average gas sales prices excluding the impact of hedging were $4.47 per thousand cubic feet in 2010 comparedto $4.13 per thousand cubic feet in 2009. CBM sales volumes increased 4.5 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. We had 3,945 net CBM Wells at December 31, 2010 compared to 3,688 net CBM wells at December 31, 2009. Also, 2009 CBMvolumes were lower by approximately 1.2 billion cubic feet of deferrals related to the idling of the Buchanan Mine for approximately five months during 2009.Total costs for the CBM gas segment were $325 million for the year ended December 31, 2010 compared to $293 million for the year endedDecember 31, 2009. The $32 million increase in total costs in the period-to-period comparison reflects the 5.0% increase in average unit costs and the 5.2%increase in sales volumes.CBM lifting costs were $50 million for the year ended December 31, 2010 compared to $49 million for the year ended December 31, 2009. AverageCBM lifting costs per unit were $0.54 per thousand cubic feet for 2010 compared to $0.57 per thousand cubic feet for 2009. The improvement in averageCBM lifting costs per unit was due to lower salt water disposal costs attributable to recycling the water produced from our wells to be used in hydraulicfracturing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Unit costs were also improved due to highervolumes of CBM gas sold in the period-to-period comparison resulting in fixed costs being spread over additional volumes, lowering the average per unit costs.These improvements were offset, in part, by higher severance taxes. Higher severance taxes were the result of average market price increases, excluding theimpact of our hedging program. Severance taxes were also higher as a result of the Buchanan County, Virginia severance tax settlement which changed thedeductions allowed in the calculation of severance tax due when the price of gas falls between certain ranges.CBM Gathering costs were $97 million for the year ended December 31, 2010 compared to $88 million for the year ended December 31, 2009. AverageCBM gathering cost were $1.06 per thousand cubic feet sold for the year ended December 31, 2010 compared to $1.01 per thousand cubic feet sold for theyear ended December 31, 2009. Higher average unit costs were related to higher power costs attributable to utility rate increases in the period-to-periodcomparison as well as increased usage. Higher average unit costs were also attributable to additional in-transit costs related to additional capacity of firmtransportation being purchased after 2009 to assure delivery of additional volumes being produced. These cost increases were offset, in part, by the 5.2%increase in volumes sold.90General and direct administrative costs attributable to the Total Gas segment have increased $26 million to $93 million for the year ended December 31,2010 compared to $67 million for the year ended December 31, 2009. The increase was attributable to additional staffing and additional corporate servicecharges from CONSOL Energy. With the Dominion Acquisition, which closed on April 30, 2010, the majority of the operational support personnel wereretained. Total Company general administrative costs have also increased, as explained previously, which resulted in additional charges being allocated to allsegments.General and direct administrative costs attributable to the CBM gas segment were $65 million for the year ended December 31, 2010 compared to $62million for the year ended December 31, 2009. General and direct administrative expenses attributable to the Total Gas segment are allocated to each individualgas segment based on a combination of production and employee counts. Although Total Gas general and direct administrative costs have increased $26million, as discussed above, the percentage allocated to the CBM segment is lower, on a unit basis, as the result of CBM production volumes to total gasvolumes produced being lower primarily due to the Dominion Acquisition, which closed on April 30, 2010.Depreciation, depletion and amortization attributable to the CBM segment was $113 million for the year ended December 31, 2010 compared to $94million for the year ended December 31, 2009. There was approximately $87 million, or $0.98 per unit-of-production, of depreciation, depletion andamortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31,2010. The unit-of-production portion of depreciation, depletion and amortization was $71 million, or $0.82 per unit-of-production in the year endedDecember 31, 2009. The CBM unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net book value ofassets divided by either proved or proved developed reserves at the previous year end. The in-field drilling program and certain assets acquired in theDominion Acquisition caused the rate to increase. There was approximately $26 million, or $0.27 per thousand cubic feet of depreciation, depletion andamortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2010. The straight-linecomponent was $23 million, or $0.26 per thousand cubic feet for the year ended December 31, 2009. The increase was related to additional gathering assetsplaced in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.SHALLOW OIL AND GAS SEGMENT:The shallow oil and gas segment had a loss before income tax of $4 million for the year ended December 31, 2010 compared to a loss before income taxof $2 million for the year ended December 31, 2009. The shallow oil and gas segment revenue and cost components on a per unit basis are as follows: For the Years Ended December 31, 2010 2009 Variance PercentChangeProduced gas Shallow Oil and Gas sales volumes (in billion cubic feet)24.7 1.7 23.0 1,352.9 %Average Shallow Oil and Gas sales price per thousand cubic feet sold$4.73 $4.33 $0.40 9.2 %Average Shallow Oil and Gas lifting costs per thousand cubic feet sold$1.24 $2.76 $(1.52) (55.1)%Average Shallow Oil and Gas gathering costs per thousand cubic feet sold$0.75 $0.59 $0.16 27.1 %Average Shallow Oil and Gas general & direct administrative costs per thousandcubic feet sold$0.88 $0.46 $0.42 91.3 %Average Shallow Oil and Gas depreciation, depletion and amortization costs perthousand cubic feet sold$2.03 $2.30 $(0.27) (11.7)% Total Average Shallow Oil and Gas costs per thousand cubic feet sold$4.90 $6.11 $(1.21) (19.8)% Average Margin for Shallow Oil and Gas$(0.17) $(1.78) $1.61 (90.4)%Shallow Oil and Gas segment sales revenues were $116 million for the year ended December 31, 2010 compared to $8 million for the year endedDecember 31, 2009. Shallow Oil and Gas sales volumes increased 23.0 billion cubic feet for the year ended December 31, 2010 primarily due to the DominionAcquisition, which closed on April 30, 2010. Approximately 95% of the acquired producing wells were shallow oil and gas type wells. There were 8,016 netShallow Oil and Gas wells at December 2010 compared to 195 net Shallow Oil and Gas wells at December 31, 2009. No Shallow Oil and Gas gas volumeswere hedged in 2010 or 2009.Total costs for the Shallow Oil and Gas segment were $120 million for the year ended December 31, 2010 compared to $10 million for the year endedDecember 31, 2009. The increase of $110 million is attributable to additional volumes sold in the period-to-period comparison, offset, in part, by loweraverage unit costs sold. Shallow Oil and Gas average unit costs have decreased due to the significant increase in volumes related to production from wellsacquired in the Dominion Acquisition, which closed on91April 30, 2010. A detailed analysis of cost categories is not meaningful due to the significant change in this segment related to the Dominion Acquisition andwill therefore not be presented. General and direct administrative costs attributable to the Total Gas segment are allocated to each individual gas segment basedon a combination of production and employee counts. Shallow Oil and Gas volumes are higher as a percent of total gas produced volumes in the period-to-period comparison and therefore, additional general and direct administrative costs have been allocated to the Shallow Oil and Gas gas segment in 2010.MARCELLUS SEGMENT:The Marcellus segment contributed $6 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $4million for the year ended December 31, 2009. The Marcellus segment revenue and cost components on a per unit basis are as follows: For the Years Ended December 31, 2010 2009 Variance PercentChangeProduced gas Marcellus sales volumes (in billion cubic feet)10.4 5.0 5.4 108.0 %Average Marcellus sales price per thousand cubic feet sold$4.69 $4.24 $0.45 10.6 %Average Marcellus lifting costs per thousand cubic feet sold$0.50 $0.12 $0.38 316.7 %Average Marcellus gathering costs per thousand cubic feet sold$0.99 $1.12 $(0.13) (11.6)%Average Marcellus general & direct administrative costs perthousand cubic feet sold$0.73 $0.74 $(0.01) (1.4)%Average Marcellus depreciation, depletion and amortization costs perthousand cubic feet sold$1.90 $1.47 $0.43 29.3 % Total Average Marcellus costs per thousand cubic feet sold$4.12 $3.45 $0.67 19.4 % Average Margin for Marcellus$0.57 $0.79 $(0.22) (27.8)%The increase in Marcellus average sales price was the result of an improvement in general market prices and various gas swap transactions that occurredin the year ended December 31, 2010. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physicaltransactions. These financial hedges represented approximately 1.6 billion cubic feet of our produced Marcellus gas sales volumes for the year endedDecember 31, 2010 at an average price of $5.05 per thousand cubic feet. There were no gas swap transactions for the Marcellus segment that occurred for theyear ended December 31, 2009. The increase in sales volumes was primarily due to additional wells coming on-line from our on-going drilling program. AtDecember 31, 2010 there were 52 Marcellus Shale wells in production including 17 wells acquired in the Dominion Acquisition, which closed on April 30,2010. At December 31, 2009 there were 22 Marcellus Shale wells in production.Total costs for the Marcellus segment were $43 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31,2009. The increase was primarily due to the additional sales volumes and higher average unit costs.Marcellus lifting costs were $5 million for the year ended December 31, 2010 compared to $1 million for the year ended December 31, 2009. AverageMarcellus lifting costs were $0.50 per thousand cubic feet in 2010 compared to $0.12 per thousand cubic feet in 2009. The increase in average lifting costs perunit sold was due to increased road repairs and other maintenance expense primarily related to the additional number of wells drilled in the current period. Saltwater disposal fees were also higher in the period-to-period comparison due to the higher volume of water produced from additional wells. These increases incosts were offset, in part, by the additional volume of Marcellus gas sold in the period-to-period comparison.Marcellus gathering costs were $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009.Average gathering cost per unit sold was $0.99 per thousand cubic feet for the year ended December 31, 2010 compared to $1.12 per thousand cubic feet forthe year ended December 31, 2009. Lower average gathering cost per unit was primarily attributable to the 108.0% increase in volumes sold. This improvementwas offset, in part, by higher power and security costs. Higher power costs were related to higher rates being charged by utility companies in the period-to-period comparison. Higher security costs were related to additional security needs at various Marcellus gathering stations.General and direct administrative costs attributable to the Marcellus gas segment were $8 million for the year ended December 31, 2010 compared to $4million for the year ended December 31, 2009. Average general and direct administrative costs on a per unit sold basis were $0.73 per thousand cubic feet forthe year ended December 31, 2010 compared to $0.74 per thousand cubic feet for the year ended December 31, 2009. General and direct administrative costsattributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. The total generaland direct administrative cost increases, as discussed previously, were offset, in part, by higher volumes of gas produced from92Marcellus wells.Depreciation, depletion and amortization attributable to the Marcellus segment was $20 million for the year ended December 31, 2010 compared to $7million for the year ended December 31, 2009. There was approximately $18 million, or $1.72 per unit-of-production, of depreciation, depletion andamortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the year endedDecember 31, 2010. The unit-of-production portion of depreciation, depletion and amortization was $6 million, or $1.27 per unit-of-production in the yearended December 31, 2009. The Marcellus unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net bookvalue of assets divided by either proved or proved developed reserves at the previous year end. The investment in drilling activities increased in higherproportion than the related gas reserves in the current period, which resulted in a higher per unit rate. There was approximately $2 million, or $0.18 perthousand cubic feet of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the yearended December 31, 2010. The straight-line component was $1 million, or $0.20 per thousand cubic feet for the year ended December 31, 2009. The increasewas related to additional gathering assets placed in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.OTHER GAS SEGMENT:The Other gas segment includes activity not assigned to CBM, Conventional or Marcellus gas segments. This segment includes purchased gas activity,gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific gassegment. The other gas segment had a loss before income tax of $70 million for the year ended December 31, 2010 compared to a loss before income tax of$43 million for the year ended December 31, 2009.Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately$8 million for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. There was 1.4 billion cubic feet sold fromthis area for the year ended December 31, 2010 compared to 0.8 billion cubic feet for the year ended December 31, 2009. Total costs related to these other saleswere $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009. The increase in costs in the period-to-period comparison was primarily due to higher depreciation, depletion and amortization attributable to the additional 0.6 billion cubic feet of gas produced andhigher unit-of-production rates. The higher units-of-production rates were related to a higher proportion of capital assets placed in service versus the proportionof proved developed reserve additions. A per unit analysis of the other operating costs in Chattanooga is not meaningful due to the low volumes produced in theperiod-to-period analysis.Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energygas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royaltiescontributed to the period-to-period change. Royalty interest gas sales revenues were $63 million for the year ended December 31, 2010 compared to $41 millionfor the year ended December 31, 2009. For the Years Ended December 31, 2010 2009 Variance PercentChangeGas Royalty Interest Sales Volumes (in billion cubic feet)14.2 9.8 4.4 44.9%Average Sales Price Per thousand cubic feet$4.41 $4.17 $0.24 5.8%Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas salesrevenues were $11 million for the year ended December 31, 2010 compared to $7 million for the year ended December 31, 2009. For the Years Ended December 31, 2010 2009 Variance PercentChangePurchased Gas Sales Volumes (in billion cubic feet)2.0 1.6 0.4 25.0%Average Sales Price Per thousand cubic feet$5.48 $4.46 $1.02 22.9%Other income was consistent at $5 million for the years ended December 31, 2010 and 2009.Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gassegment. The changes in market prices, contractual differences among leases, and the mix of average93and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales costs were $54 million for the year endedDecember 31, 2010 compared to $32 million for the year ended December 31, 2009. For the Years Ended December 31, 2010 2009 Variance PercentChangeGas Royalty Interest Sales Volumes (in billion cubic feet)14.2 9.8 4.4 44.9%Average Cost Per thousand cubic feet sold$3.78 $3.30 $0.48 14.5%Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact ofpipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes, contractual differences among customers and the pipelineimbalance. Purchased gas costs were $10 million for the year ended December 31, 2010 compared to $6 million for the year ended December 31, 2009. For the Years Ended December 31, 2010 2009 Variance PercentChangePurchased Gas Volumes (in billion cubic feet)1.9 1.7 0.2 11.8%Average Cost Per thousand cubic feet sold$5.14 $3.75 $1.39 37.1%Exploration and other costs were $25 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009.The $8 million increase was made up of the following items: For the Years Ended December 31, 2010 2009 Variance PercentChangeDry Hole and Lease Expiration Costs$21 $14 $7 50.0%Exploration4 3 1 33.3%Total Exploration and Other Costs$25 $17 $8 47.1%Dry hole and lease expiration costs were $7 million higher in the period-to-period comparison primarily due to lease surrenders in the current year,offset, in part, by lower dry wells drilled in the year ended December 31, 2010.Exploration costs increased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none ofwhich were individually material.Other corporate expenses were $56 million for the year ended December 31, 2010 compared to $33 million for the year ended December 31, 2009. The$23 million increase was due to the following items: For the Years Ended December 31, 2010 2009 Variance PercentChangeShort-term incentive compensation$24 $16 $8 50.0 %Stock-based compensation16 11 5 45.5 %Variable interest earnings4 — 4 100.0 %Bank fees4 — 4 100.0 %Financing and acquisition fees3 — 3 100.0 %Contract settlement— 3 (3) (100.0)%Other5 3 2 66.7 %Total Other Corporate Expenses$56 $33 $23 69.7 %•The short-term incentive compensation program is designed to increase compensation to eligible employees when the gas segment reachespredetermined 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 inthe total company general and administrative area were primarily related to support staff retained in the Dominion Acquisition,which closed onApril 30, 2010 and additional hiring to support operations.94•Stock-based compensation is higher in the period-to-period comparison primarily due to the conversion of the CNX Gas performance share unitsto CONSOL Energy restricted stock units in the year ended December 31, 2009. The conversion resulted in a reduction of approximately $4million of expense in 2009. Additional expense was also related to stock-based compensation allocated from CONSOL Energy to the gas segmentin 2010. These increases were offset, in part, by the non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-intransaction. The expense previously recognized for these options was reversed on the gas segment. All stock-based compensation is now allocatedfrom CONSOL Energy.•Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holdsno ownership interest, but guarantees bank loans the entity holds related to its purchases of drilling rigs. CONSOL Energy is also the maincustomer of the third party, and based on analysis is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact isfully 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 areprimarily 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 incertain 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 beingallocated to the operating gas segments and various other transactions that occurred throughout both periods, none of which were individuallymaterial.Interest expense was $7 million for the year ended December 31, 2010 compared to $8 million for the year ended December 31, 2009. Interest is incurredby the gas segment on the gas segment revolving credit facility, a capital lease and debt held by a variable interest entity. No significant changes in thesecomponents occurred in the period-to-period comparison.Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which theCONSOL Energy gas segment holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas segment has been determined to be theprimary beneficiary due to guarantees of the third party's bank debt related to their purchase of drilling rigs. The third party entity provides drilling servicesprimarily to the CONSOL Energy gas segment. CONSOL Energy consolidates the entity and then reflects 100% of the impact as noncontrolling interest. Theconsolidation does not significantly impact any amounts reflected in the gas segment income statement. The variance in the noncontrolling interest amountsreflects the third party's variance in earnings in the period-to-period comparison.95OTHER SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:The other segment includes activity from sales of industrial supplies, transportation operations and various other corporate activities that are notallocated to the coal or gas segment. The other segment had a loss before income tax of $249 million for the year ended December 31, 2010 compared to a lossof $22 million for the year ended December 31, 2009. The other segment also includes total company income tax expense of $109 million for the year endedDecember 31, 2010 and $221 million for the year ended December 31, 2009. For the Years Ended December 31, 2010 2009 Variance PercentChangeSales—Outside$297 $273 $24 8.8 %Other Income29 29 — — %Total Revenue326 302 24 7.9 %Cost of Goods Sold and Other Charges349 267 82 30.7 %Depreciation, Depletion & Amortization18 20 (2) (10.0)%Taxes Other Than Income Tax10 13 (3) (23.1)%Interest Expense198 24 174 725.0 %Total Costs575 324 251 77.5 %Loss Before Income Tax(249) (22) (227) (1,031.8)%Income Tax109 221 (112) (50.7)%Net Loss$(358) $(243) $(115) (47.3)%Industrial Supplies:Total revenues from industrial supply operations were $195 million for the year ended December 31, 2010 compared to $196 million for the year endedDecember 31, 2009.Total costs related to industrial supply sales were $197 million for the year ended December 31, 2010 compared to $190 million for the year endedDecember 31, 2009. The $7 million increase in expense is primarily due to changes in last-in-first-out valuations.Transportation operations:Total revenue from transportation operations was $114 million for the year ended December 31, 2010 compared to $84 million for the year endedDecember 31, 2009. The $30 million increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-periodcomparison.Total costs related to transportation operations were $81 million for the year ended December 31, 2010 compared to $70 million for the year endedDecember 31, 2009. The $11 million increase was primarily related to the additional through-put tons at the Baltimore terminal in the period-to-periodcomparison.Miscellaneous Other:Other income was $17 million for the year ended December 31, 2010 compared to $22 million for the year ended December 31, 2009. The $5 milliondecrease was attributable to $6 million of Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the Company'sprevious headquarters in 2009. This was offset by $1 million related to various transactions that occurred throughout both periods, none of which wereindividually material.Other corporate costs include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were$297 million for the year ended December 31, 2010 and $64 million for the year ended December 31, 2009. Other corporate costs increased $233 million dueto the following:•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 inconjunction 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 debtissuance that raised approximately $4.6 billion dollars. These fees also include costs related to96extending and refinancing the CONSOL Energy revolving credit facility, the Dominion Acquisition and the purchase of the CNX Gasnoncontrolling interest.•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. Theincrease 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 individuallymaterial.•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 useof the Company's previous headquarter liability. The year ended December 31, 2009 included $13 million of expense related to the cease use of thefacility. 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 theeconomic downturn that occurred.Income Taxes:The effective income tax rate was 23.4% for the year ended December 31, 2010 compared to 28.1% for the year ended December 31, 2009. The effectivetax rate is sensitive to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings alsoimpacts the benefit of percentage depletion on the effective tax rate. The mix of pre-tax income by state may also impact the overall effective tax rate. The pre-taxincome mix by state has changed in the period-to-period comparison due to the Dominion Acquisition. See Note 6-Income Taxes in the Notes to the AuditedConsolidated Financial Statements in Item 8 of this Form 10-K for additional explanation of the effective tax rate change in the period-to-period comparison. For the Years Ended December 31, 2010 2009 Variance PercentChangeTotal Company Earnings Before Income Tax$468 $788 $(320) (40.6)%Income Tax Expense$109 $221 $(112) (50.7)%Effective Income Tax Rate23.4% 28.1% (4.7)% Critical Accounting PoliciesThe preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requiresmanagement to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and relateddisclosure of contingent assets and liabilities in the consolidated financial statements and at the date of the financial statements. See Note 1–SignificantAccounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. On an on-going basis,we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under thecircumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparentfrom other sources. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimatesutilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation ofthe Consolidated Financial Statements.Business CombinationsAt acquisition, CONSOL Energy allocates the cost of a business acquisition to the specific tangible and intangible assets acquired and liabilitiesassumed based upon their relative fair values. Significant judgments and estimates are often made to determine these allocated values, and may include the useof appraisals, consideration of market quotes for similar transactions, employment of discounted cash flow techniques or consideration of other informationCONSOL Energy believes relevant. The finalization of the purchase price allocation will typically take a number of months to complete, and if final valuesare materially different from initially recorded amounts, adjustments are recorded. Any excess of the cost of a business acquisition over the fair values of thenet assets and liabilities acquired is recorded as goodwill which is not amortized to expense. Recorded goodwill of a reporting unit is required to be tested forimpairment on an annual basis, and between annual testing97dates if events or circumstances change that would more likely than not reduce the fair value of a reporting unit below its net book value.Subsequent to the finalization of the purchase price allocation, any adjustments to the recorded values of acquired assets and liabilities would bereflected in the consolidated statement of operations. Once final, it is not permitted to revise the allocation of the original purchase price, even if subsequentevents or circumstances prove the original judgments and estimates to be incorrect. In addition, long-lived assets like property and equipment, amortizableintangibles and goodwill may be deemed to be impaired in the future resulting in the recognition of an impairment loss. The assumptions and judgments madewhen recording business combinations will have an impact on reported results of operations for many years into the future.Other Post Employment Benefits (OPEB)Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry RetireeHealth Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networksand coordination with Medicare. For salaried employees hired before January 1, 2007, the eligibility requirement is either age 55 with 20 years of service or age62 with 15 years of service. Also, salaried employees and retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher,dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared byCONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility ofthe participants. Any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007 or later will not become eligible forretiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medicalspending allowance of $2,250 per year for each year of service at retirement. Newly employed inexperienced miners represented by the United Mine Workersof America (UMWA), hired after January 1, 2007, will not be eligible to receive retiree health benefits. In lieu of these benefits, these employees will receive adefined contribution benefit of $1 per each hour worked through December 31, 2013, increasing to $1.50 per hour worked effective January 1, 2014 throughDecember 31, 2016.After our review, various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, averageremaining life expectancy, per capita costs and participation level in each future year are used by our independent actuary to estimate the cost and benefitobligations for our retiree health plans. Expected trends in future health care cost assumptions were adjusted from prior year to reflect recent experience andfuture expectations. The initial expected trend in health care costs at this year's measurement date of 6.85% with an ultimate trend rate of 4.50% reached in2026. The initial expected trend rate at last year's measurement date was 8.47% with an ultimate trend rate of 4.50% reached in 2023. A 1.0% decrease in thehealth care trend rate would decrease interest and service cost for 2011 by approximately $20.9 million. A 1.0% increase in the health care trend rate wouldincrease the interest and service cost by approximately $24.9 million. The discount rate is determined each year at the measurement date. The discount rate isdetermined by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody's as of the measurement date.All future post employment benefit expected payments were discounted using a spot rate yield curve as of December 31, 2011. The appropriate discount ratewas then selected from resulting discounted cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period endliability and the following year's expense was 4.51% and 5.33%, respectively. A 0.25% increase in the discount rate would have decreased 2011 net periodicpostretirement benefit costs by approximately $4.7 million. A 0.25% decrease in the discount rate would have increased 2011 net periodic postretirementbenefit costs by approximately $5.5 million. Deferred gains and losses are primarily due to historical changes in the discount rate and medical cost inflationdiffering from expectations in prior years. Changes to interest rates for the rates of returns on instruments that could be used to settle the actuarially determinedplan obligations introduce substantial volatility to our costs. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on astraight-line basis over the expected future service of active salary and non-represented employees to their assumed retirement age. At December 31, 2011 theaverage remaining service period is approximately 11 years for our non-represented plans. Accumulated actuarial gains or losses in excess of a pre-establishedcorridor are amortized on a straight-line basis over the expected remaining life of our retired UMWA population. The average remaining service period of thispopulation is not used for amortization purposes because the majority of the UMWA population of our plan is retired. At December 31, 2011, the averageremaining life expectancy of our retired UMWA population used to calculate the following year's expense is approximately 13 years.The weighted average per capita costs used to value the December 31, 2011 Other Postretirement Benefit liability was approximately 7% less thanpreviously expected based on our trend assumption. If the actual change in per capita cost of medical services or other postretirement benefits are significantlygreater or less than the projected trend rates, the per capita cost assumption would need to be adjusted, which could have a significant effect on the costs andliabilities recorded in the financial statements.98Significant increases in health and prescription drug costs for represented hourly retirees could have a material adverse effect on CONSOL Energy'soperating cash flow. However, the effect on CONSOL Energy's cash flow from operations for salaried employees is limited to approximately 6% of theprevious year's medical cost for salaried employees due to the cost sharing provision in the benefit plan.The estimated liability recognized in the December 31, 2011 financial statements was $3.2 billion. For the year ended December 31, 2011, we paidapproximately $156.8 million for other postretirement benefits, all of which were paid from operating cash flow. Our obligations with respect to theseliabilities are unfunded at December 31, 2011. CONSOL Energy does not expect to contribute to the other postretirement plan in 2012. We intend to pay benefitclaims as they are due.Salaried PensionsCONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. Thebenefits for these plans are based primarily on years of service and employee's pay near retirement. CONSOL Energy's salaried plan allows for lump-sumdistributions of benefits earned up until December 31, 2005, at the employees' election. The Restoration Plan was frozen effective December 31, 2006 and wasreplaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy's Restoration Plan allows only for lump-sum distributionsearned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas. TheSupplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL EnergyDefined Contribution Restoration Plan.In March of 2009, the CNX Gas defined benefit retirement plan was merged into the CONSOL Energy's non-contributory defined benefit retirementplan. At the time, the change did not impact the benefits for employees of CNX Gas. However, during 2010 an amendment was adopted to recognize pastservice at CNX Gas to current employees of CNX Gas who opted out of the plan for additional company contributions into their defined contribution plan andextend coverage to employees previously not eligible to participate in this plan.Our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates ofcompensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2011, compensation increases are assumed to range from 3%to 6% depending on age and job classification. The discount rate is determined each year at the measurement date. The discount rate is determined by utilizinga corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody's as of the measurement date. All expected benefitpayments from the CONSOL Energy retirement plan were discounted using a spot rate yield curve as of December 31, 2011. The appropriate equivalentdiscount rate was then selected for the resulting discounted pension cash flows. For the years ended December 31, 2011 and 2010, the discount rate used tocalculate the period end liability and the following year's expense was 4.50% and 5.30%, respectively. A 0.25% increase in the discount rate would havedecreased the 2011 net periodic pension cost by $1.9 million. A 0.25% decrease in the discount rate would have increased the 2011 net periodic pension costby $2.0 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations. AtDecember 31, 2011 the average remaining service period is approximately 10 years. Changes to any of these assumptions introduce substantial volatility to ourcosts.The market related asset value is derived by taking the cost value of assets as of December 31, 2011 and multiplying it by the average 36-month ratioof the market value of assets to the cost value of assets. CONSOL Energy's pension plan weighted average asset allocations at December 31, 2011 consisted of60% equity securities and 40% debt securities.The estimated liability recognized in the December 31, 2011 financial statements was $274.8 million. For the year ended December 31, 2011, wecontributed approximately $72.2 million to defined benefit retirement plans other than multi-employer plans trust and to other pension benefits. Ourobligations with respect to these liabilities are partially funded at December 31, 2011. CONSOL Energy intends to contribute an amount that will avoid benefitrestrictions for the following plan year.Workers' Compensation and Coal Workers' PneumoconiosisWorkers' compensation is a system by which individuals who sustain employment related physical injuries or some type of occupational diseases arecompensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers' compensation will also compensate thesurvivors of workers who suffer employment related deaths. The workers' compensation laws are administered by state agencies with each state having itsown set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy records anactuarially calculated liability, which is determined using various assumptions, including discount rate, future healthcare cost trends, benefit duration andrecurrence of injuries. The discount rate is determined each year at the measurement date. The discount rate is determined by utilizing a corporate yield curvemodel developed from corporate bond data using only bonds rated Aa by Moody's as of the measurement date. All future workers' compensation expectedbenefit payments were discounted99using a spot rate yield curve as of December 31, 2011. The appropriate equivalent discount rate was then selected from the resulting discounted workers'compensation cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the following year'sexpense was 4.40% and 5.13%, respectively. A 0.25% increase in the discount rate would have decreased the 2011 workers compensation expense cost by $0.7million. A 0.25% decrease in the discount rate would have increased the 2011 workers compensation expense by $0.7 million. Deferred gains and losses areprimarily due to historical changes in the discount rates, several years of favorable claims experience, various favorable state legislation changes and an overalllower incident rate than our assumptions. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expected future service of activeemployees that are eligible to file a future workers' compensation claim. At December 31, 2011, the average remaining service period is approximately 9 years.The estimated liability recognized in the financial statements at December 31, 2011 was approximately $174.1 million. CONSOL Energy's policy has been toprovide for workers' compensation benefits from operating cash flow. For the year ended December 31, 2011, we made payments for workers' compensationbenefits and other related fees of approximately $32.9 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilitiesare unfunded at December 31, 2011. CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits toemployees and their dependents resulting from occurrences of coal workers' pneumoconiosis disease. CONSOL Energy is also responsible under various statestatutes for pneumoconiosis benefits. After our review, our independent actuaries calculate the actuarial present value of the estimated pneumoconiosisobligation based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate isdetermined each year at the measurement date. The discount rate is determined by utilizing a corporate yield curve model developed from corporate bond datausing only bonds rated Aa by Moody's as of the measurement date. All future coal workers' pneumoconiosis expected benefit payments were discounted usinga spot rate yield curve at December 31, 2011. The appropriate equivalent discount rate was then selected from the resulting discounted coal workers'pneumoconiosis cash flows. For the years ended December 31, 2011 and 2010, the discount rate used to calculate the period end liability and the followingyear's expense was 4.46% and 5.21%, respectively. A 0.25% increase in the discount rate would have increased 2011 coal workers' pneumoconiosis benefit by$0.6 million. A 0.25% decrease in the discount rate would have decreased 2011 coal workers' pneumoconiosis benefit by $0.6 million. Actuarial gainsassociated with coal workers' pneumoconiosis have resulted from numerous legislative changes over many years which have resulted in lower approval ratesfor filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed thanour assumptions originally reflected. The estimated liability recognized in the financial statements at December 31, 2011 was $183.6 million. For the yearended December 31, 2011, we paid coal workers' pneumoconiosis benefits of approximately $11.1 million, all of which was paid from operating cash flow.Our obligations with respect to these liabilities are unfunded at December 31, 2011.Reclamation, Mine Closure and Gas Well Closing ObligationsThe Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as wellas most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine and gas well closure, including the cost oftreating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities, and gas well closing which are based upon permitrequirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $650.1 million atDecember 31, 2011. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by CONSOL Energymanagement and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations changesignificantly.Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it isincurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carryingamount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustionof coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing, reclamation and gas wellclosing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs,estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate. Accounting for Asset Retirement Obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirementobligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over thelife of the producing assets, typically as production declines.100Income TaxesDeferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax basis ofrecorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax assetwill not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31,2011, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $648.8 million. The deferred tax assets are evaluatedperiodically to determine if a valuation allowance is necessary.Deferred tax valuation allowances decreased $21.7 million in the year ended December 31, 2011 primarily due to the release of previously recognizedvaluation allowances related to certain Pennsylvania net operating loss carry forwards and future temporary deductions. Valuation allowances on these netoperating loss carry forwards and future temporary deductions were released during the year due to positive evidence outweighing negative evidence indicatingthat these benefits will be utilized in future years. CONSOL Energy continues to report a deferred tax asset of approximately $35.0 million relating to its statenet operating loss carry forwards subject to a full valuation allowance. A review of positive and negative evidence regarding these benefits, primarily thehistory of financial and tax losses on a separate company basis, concluded that a full valuation allowance was warranted. The net operating loss carryforwards expire at various times from 2018 to 2030. A valuation allowance of $6.0 million continues to be recognized against the state deferred tax assetattributable to future tax deductible differences for certain subsidiaries with histories of financial and tax losses. Management will continue to assess therealization of deferred tax assets attributable to state net operating loss carry forwards and future tax deductible differences based upon updated income forecastdata and the feasibility of future tax planning strategies, and may record adjustments to valuation allowances against these deferred tax assets in future periodsthat could materially impact net income.CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustainedupon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determinedon a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position isderecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of thesustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various otherassumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form thebasis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. Estimates ofour uncertain tax liabilities, including interest and the current portion, were approximately $30.9 million at December 31, 2011.Stock-Based CompensationAs of December 31, 2011, we have issued four types of share based payment awards: options, restricted stock units, performance stock options andperformance share units. The Black-Scholes option pricing model is used to determine fair value of stock options at the grant date. Various inputs are utilizedin the Black-Scholes pricing model, such as:•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.These factors can significantly impact the value of stock options expense recognized over the requisite service period of option holders.The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of our company's stock on the date of thegrant. The fair value of each performance share unit is determined by the underlying share price of our company stock on the date of the grantand management's estimate of the probability that the performance conditions required for vesting will be achieved.As of December 31, 2011, $36.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over aweighted-average period of 1.66 years. See Note 18–"Stock-based Compensation" in the Notes to the101Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.ContingenciesCONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of theseclaims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potentialresults, assuming a combination of litigation and settlement strategies. Future results of operations for any particular quarter or annual period could bematerially affected by changes in our assumptions or the outcome of these proceedings. See Note 24–Commitments and Contingent Liabilities in the Notes tothe Audited Consolidated Financial Statements in Item 8 in this Form 10-K for further discussion.Successful Efforts AccountingWe use the successful efforts method to account for our gas exploration and production activities. Under this method, cost of property acquisitions,successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory or developmentwells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves tocontinue evaluating the viability of the project. We use this accounting policy instead of the "full cost" method because it provides a more timely accounting ofthe success or failure of our gas exploration and production activities.Derivative InstrumentsCONSOL Energy enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We measure every derivativeinstrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently inearnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivativeinstrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of thederivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transactionaffects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedgesthat are considered highly effective.CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsettingchanges in fair values or cash flows of the hedge item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be ahighly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.Coal and Gas Reserve ValuesThere are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal and gas reserves, including manyfactors beyond our control. As a result, estimates of economically recoverable coal and gas reserves are by their nature uncertain. Information about ourreserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our coal reserves are periodicallyreviewed by an independent third party consultant. Our gas reserves have been reviewed by independent experts each year. Some of the factors andassumptions which impact economically recoverable reserve estimates include:•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.Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economicallyrecoverable quantities of coal and gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery andestimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary fromestimates, and these variances may be material. See "Risk Factors" in Item 1A of this report for a discussion of the uncertainties in estimating our reserves.102Liquidity and Capital ResourcesCONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations withcash generated from operations and proceeds from borrowings. On April 12, 2011, CONSOL Energy amended and extended its $1.5 billion SeniorSecured Credit Agreement through April 12, 2016. The previous facility was set to expire on May 7, 2014. The amendment provides more favorablepricing and the facility continues to be secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries. CONSOLEnergy's credit facility allows for up to $1.5 billion for borrowings and letters of credit. CONSOL Energy can request an additional $250 millionincrease in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailingearnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interestcoverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio ofEBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 5.80 to 1.00 at December 31,2011. The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00thereafter, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailingEBITDA for CONSOL Energy and certain subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters ofcredit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cashcompensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includescash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 2.15 to 1.00 at December 31,2011. The facility also includes a senior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverageratio covenant is calculated as the ratio of secured debt to EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on therevolving credit facility. The senior secured leverage ratio was 0.19 to 1.00 at December 31, 2011. Covenants in the facility limit our ability todispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another company andamend, modify or restate, in any material way, the senior unsecured notes. At December 31, 2011, the facility had no outstanding borrowings and$266 million of letters of credit outstanding, leaving $1.2 billion of unused capacity. From time to time, CONSOL Energy is required to postfinancial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted tocomply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements andthese letters of credit reduce our borrowing facility capacity.CONSOL Energy also has an accounts receivable securitization facility. This facility allows the Company to receive, on a revolving basis, upto $200 million of short-term funding and letters of credit. The accounts receivable facility supports sales, on a continuous basis to financialinstitutions, of eligible trade accounts receivable. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutionsfor a fee based upon market rates for similar services. The cost of funds is based on commercial paper rates plus a charge for administrative servicespaid to financial institutions. At December 31, 2011, eligible accounts receivable totaled approximately $193 million and there were no borrowings orletters of credit outstanding against the facility.On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% Notes due March 1, 2012 in accordance withthe terms of the indenture governing the Notes. The redemption price included principal of $250 million, a make-whole premium of $16 million andaccrued interest of $2 million for a total redemption cost of $268 million. CONSOL Energy's loss on extinguishment of debt was $16 million,which primarily represents the interest that would have been paid on these notes if held to maturity.On April 12, 2011, CNX Gas entered into a $1.0 billion Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the$700 million senior secured credit facility which was set to expire on May 6, 2014. The replacement facility provides more favorable pricing and thefacility continues to be secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0billion for borrowings and letters of credit. CNX Gas can request an additional $250 million increase in the aggregate borrowing limit amount. Feesand interest rate spreads are based on the percentage of facility utilization, measured quarterly. An amendment to the credit agreement was approvedby the lenders and became effective December 14, 2011. The amendment allows unlimited investments in joint ventures for the development andoperation of gas gathering systems and provides for $600 million of loans, advances and dividends from CNX Gas to CONSOL Energy.Investments in CONE Gathering Company, a joint venture with Noble Energy to provide Marcellus gathering capability, are unrestricted under thisamendment. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The minimum interestcoverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interest coverage ratiowas 34.18 to 1.00 at December 31, 2011. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured103quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CNX Gasand its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas andits subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gainsand losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions receivedfrom affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.00 to 1.00 at December 31, 2011. Covenants in the facilitylimit our ability to dispose of assets, make investments, pay dividends and merge with another company. At December 31, 2011, the facility had noamounts drawn and $70 million of letters of credit outstanding, leaving $930 million of unused capacity.Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, lessavailability and higher costs of additional credit, potential counterparty defaults, and commercial bank failures. Financial market disruptions mayimpact our collection of trade receivables. As a result, CONSOL Energy constantly monitors the creditworthiness of our customers. We believe thatour current group of customers are financially sound and represent no abnormal business risk.CONSOL Energy believes that cash generated from operations and our borrowing capacity will be sufficient to meet our working capitalrequirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and toprovide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy its working capital requirements, to service its debtobligations, to fund planned capital expenditures or to pay dividends will depend upon future operating performance, which will be affected byprevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOLEnergy’s control.In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gassupply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swaptransactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contractswas a net asset of $251 million at December 31, 2011. The ineffective portion of these contracts was insignificant to earnings in the year endedDecember 31, 2011. No issues related to our hedge agreements have been encountered to date.CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions with cash generated from operationsand a variety of other sources, depending on the size of the transaction, including debt and equity financing. There can be no assurance thatadditional capital resources, including debt and equity financing, will be available to CONSOL Energy on terms which CONSOL Energy findsacceptable, or at all.Cash Flows (in millions) For the Years Ended December 31, 2011 2010 ChangeCash flows from operating activities$1,528 $1,131 $397Cash used in investing activities$(579) $(5,544) $4,965Cash (used in) provided by financing activities$(606) $4,380 $(4,986)Cash flows provided by operating activities changed in the period-to-period comparison primarily due to the following items:•Operating cash flow increased $274 million in 2011 due to higher net income attributable to CONSOL Energy shareholders in the period-to-periodcomparison. The 2011 net income included an approximately $75 million reduction due to the abandonment of Mine 84 which is discussedfurther in Note 10—Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form10-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 whichoccurred throughout both years, none of which were individually material.104Net cash used in investing activities changed in the period-to-period comparison primarily due to the following items:•On April 30, 2010, CONSOL Energy paid $3.470 billion for the Dominion Acquisition. See Note 2—Acquisitions and Dispositions, in the Notesto 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 didnot previously own.•On September 30, 2011, CONSOL Energy received net proceeds of $485 million related to the Noble transaction, net proceeds of $190 millionrelated to the Antero transaction, and net proceeds of $54 million related to the Hess transaction. See Note 2—Acquisitions and Dispositions, inthe 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 andDispositions, in the Notes to the Audited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details.•Total capital expenditures increased $228 million to $1.38 billion in the year ended December 31, 2011 compared to $1.15 billion in the yearended December 31, 2010. Capital expenditures for the gas segment increased $242 million due to the additional Marcellus Shale drilling in theperiod-to-period comparison. Capital expenditures for coal and other activities decreased $14 million in the period-to-period comparison. Faceextension projects at various locations were lower by $87 million as a result of the majority of these projects being completed during the 2010period, $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 byapproximately $32 million related to the Buchanan Reverse Osmosis (RO) system which was primarily completed before January 1, 2011 and anapproximate $42 million decrease in 2011 related to various other equipment expenditures throughout both periods. These reductions in coal andother capital were offset, in part by an approximate $122 million increase in expenditures related primarily to the ongoing development of the BMXMine which is scheduled to begin production in early 2014, and a $38 million increase in 2011 related to the construction of the Northern WestVirginia RO system.Net cash (used in) provided by financing activities changed in the period-to-period comparison primarily due to the following items:•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 in2017 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 onMarch 31, 2010.•In 2011, CONSOL Energy repaid $200 million of borrowings under the accounts receivable securitization facility. In 2010, CONSOL Energyreceived 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 theAudited 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 issuedon 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% senior105unsecured notes due in March 2021.•In 2011, CNX Gas, a wholly-owned subsidiary, paid outstanding borrowings of $129 million under its revolving credit facility compared toreceiving $71 million in 2010.The following is a summary of our significant contractual obligations at December 31, 2011 (in thousands): Payments due by Year Less Than1 Year 1-3 Years 3-5 Years More Than5 Years TotalPurchase Order Firm Commitments$163,381 $81,788 $— $245,169Gas Firm Transportation57,796 134,057 128,022 450,825 770,700CONE Gathering Commitments22,500 157,600 339,800 1,198,500 1,718,400Long-Term Debt11,759 6,279 5,287 3,110,668 3,133,993Interest on Long-Term Debt244,977 490,592 491,303 554,157 1,781,029Capital (Finance) Lease Obligations8,932 14,608 10,627 29,954 64,121Interest on Capital (Finance) Lease Obligations4,247 6,846 5,223 5,713 22,029Operating Lease Obligations88,502 152,270 95,187 149,771 485,730Long-Term Liabilities—Employee Related (a)223,687 462,252 478,482 2,471,066 3,635,487Other Long-Term Liabilities (b)321,533 125,309 66,218 438,019 951,079Total Contractual Obligations (c)$1,147,314 $1,631,601 $1,620,149 $8,408,673 $12,807,737 _________________________(a)Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirementcontributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regardingamounts 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 amountsand timing of these obligations.DebtAt December 31, 2011, CONSOL Energy had total long-term debt of $3.198 billion outstanding, including the current portion of long-term debt of $21million. This long-term debt consisted of:•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 andOctober 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 andOctober 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 ofeach 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 interestat 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.106At December 31, 2011, CONSOL Energy also had no outstanding borrowings and had approximately $266 million of letters of credit outstandingunder the $1.5 billion senior secured revolving credit facility.At December 31, 2011, CONSOL Energy had no outstanding borrowings under the accounts receivable securitization facility.At December 31, 2011, CNX Gas, a wholly owned subsidiary, had no outstanding borrowings and approximately $70 million of letters of creditoutstanding under its $1.0 billion secured revolving credit facility.Total Equity and DividendsCONSOL Energy had total equity of $3.6 billion at December 31, 2011 and $2.9 billion at December 31, 2010. Total equity increased primarily due tonet income attributable to CONSOL Energy shareholders, changes in the fair value of cash flow hedges and the amortization of stock-based compensationawards. These increases were offset, in part, by the declaration of dividends and adjustments to actuarial liabilities. See the Consolidated Statements ofStockholders' Equity in Item 8 of this Form 10-K for additional details.Dividend information for the current year to date were as follows: Declaration Date Amount Per Share Record Date Payment DateJanuary 27, 2012 $0.125 February 7, 2012 February 21, 2012October 27, 2011 $0.125 November 11, 2011 November 25, 2011July 29, 2011 $0.100 August 10, 2011 August 22, 2011April 29, 2011 $0.100 May 13, 2011 May 24, 2011January 28, 2011 $0.100 February 8, 2011 February 18, 2011On 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,effective immediately.The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and noassurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will bepaid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results,contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factorsas the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends in excess of an annual rate of $0.40 per share when our leverageratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 2.15 to 1.00 and our availability was approximately$1.2 billion at December 31, 2011. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017, 2020 and 2021notes limit dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and otherpayment limitations under the indentures. There were no defaults in the year ended December 31, 2011.Off-Balance Sheet TransactionsCONSOL Energy does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities orothers that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenuesor expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Audited ConsolidatedFinancial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay asyou go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at December 31, 2011. The variousmulti-employer benefit plans are discussed in Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8of this Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations foremployee-related, environmental, performance and various other items which are not reflected on the balance sheet at December 31, 2011. Management believesthese items will expire without being funded. See Note 24—Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statementsincluded in Item 8 of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.107Recent Accounting PronouncementsIn December 2011, the Financial Accounting Standards Board issued an update to the Comprehensive Income Topic of the Accounting StandardsCodification intended to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported inother comprehensive income. This update allows entities to continue to report reclassifications out of accumulated other comprehensive income consistent withthe presentation requirements in effect before Update 2011-05. All other requirements included within Update 2011-05 are not affected and entities must reportcomprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. The effective date of this updateis for fiscal years, and interim periods within those years, beginning after December 15, 2011. We believe adoption of this new guidance will not have amaterial impact on CONSOL Energy's financial statements as these updates have an impact on presentation only.ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKIn addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The followingdiscussion provides additional detail regarding CONSOL Energy's exposure to the risks of changing commodity prices, interest rates and foreign exchangerates.CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal.CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOLEnergy uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives andHedging Topic of the Financial Accounting Standards Board Accounting Standards Codification to minimize exposure to market price volatility in the sale ofnatural gas. Our risk management policy prohibits the use of derivatives for speculative purposes.CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing ofcommodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading.They are used primarily to mitigate uncertainty, volatility and cover underlying exposures. CONSOL Energy's market risk strategy incorporates fundamentalrisk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.CONSOL Energy believes that the use of derivative instruments, along with our risk assessment procedures and internal controls, mitigates ourexposure to material risks. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy'sresults of operations depending on market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financialposition or liquidity.For a summary of accounting policies related to derivative instruments, see Note 1—Significant Accounting Policies in the Notes to the AuditedConsolidated Financial Statements in Item 8 of this Form 10-K.A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at December 31,2011. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $0.7 million. Similarly, ahypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $0.7 million.CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2011, CONSOLEnergy had $3,198 million aggregate principal amount of debt outstanding under fixed-rate instruments and no debt outstanding under variable-rateinstruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there wereno borrowings outstanding at December 31, 2011. CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 4.08% per annumduring the year ended December 31, 2011. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not havesignificantly decreased net income for the period. CNX Gas, also had borrowings during the period under its revolving credit facility which bears interest at avariable rate. CNX Gas’ facility had no outstanding borrowings at December 31, 2011 and bore interest at a weighted average rate of 2.08% per annum duringthe year ended December 31, 2011. Due to the level of borrowings against this facility and the low weighted average interest rate in the year ended December 31,2011, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income for the period.Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currencyexchange-rate risks.108Hedging VolumesAs of January 23, 2012 our hedged volumes for the periods indicated are as follows: For the Three Months Ended March 31, June 30, September 30, December 31, Total Year2012 Fixed Price Volumes Hedged Mcf19,108,632 19,108,632 19,318,617 19,318,617 76,854,498Weighted Average Hedge Price/Mcf$5.25 $5.25 $5.25 $5.25 $5.252013 Fixed Price Volumes Hedged Mcf12,513,747 12,652,788 12,791,830 12,791,830 50,750,195Weighted Average Hedge Price/Mcf$5.06 $5.06 $5.06 $5.06 $5.062014 Fixed Price Volumes Hedged Mcf10,849,825 10,970,378 11,090,932 11,090,932 44,002,067Weighted Average Hedge Price/Mcf$5.20 $5.20 $5.20 $5.20 $5.202015 Fixed Price Volumes Hedged Mcf927,835 938,144 948,454 948,454 3,762,887Weighted Average Hedge Price/Mcf$3.97 $3.97 $3.97 $3.97 $3.97109ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAINDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageReport of Independent Registered Public Accounting Firm111Consolidated Statements of Income for the Years Ended December 31, 2011, 2010 and 2009112Consolidated Balance Sheets at December 31, 2011 and 2010113Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2011, 2010 and 2009115Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009116Notes to the Audited Consolidated Financial Statements117110Report of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of CONSOL Energy Inc. and SubsidiariesWe have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2011 and 2010, and therelated consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. Our auditsalso included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company'smanagement. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe thatour audits provide a reasonable basis for our opinion.In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL EnergyInc. and Subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in theperiod ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statementschedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forththerein.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy Inc.and Subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2012 expressed an unqualified opinionthereon./s/ Ernst & Young LLPPittsburgh, PennsylvaniaFebruary 10, 2012111CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME(Dollars in thousands, except per share data) For the Years Ended December 31, 2011 2010 2009Sales—Outside$5,660,813 $4,938,703 $4,311,791Sales—Gas Royalty Interests66,929 62,869 40,951Sales—Purchased Gas4,344 11,227 7,040Freight—Outside231,536 125,715 148,907Other Income (Note 3)153,620 97,507 113,186Total Revenue and Other Income6,117,242 5,236,021 4,621,875Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion andamortization shown below)3,501,189 3,262,327 2,757,052Gas Royalty Interests Costs59,331 53,775 32,376Purchased Gas Costs3,831 9,736 6,442Freight Expense231,347 125,544 148,907Selling, General and Administrative Expenses175,576 150,210 130,704Depreciation, Depletion and Amortization618,397 567,663 437,417Interest Expense (Note 4)248,344 205,032 31,419Taxes Other Than Income (Note 5)344,460 328,458 289,941Abandonment of Long-Lived Assets115,817 — —Loss on Debt Extinguishment16,090 — —Transaction and Financing Fees14,907 65,363 —Black Lung Excise Tax Refund— — (728)Total Costs5,329,289 4,768,108 3,833,530Earnings Before Income Taxes787,953 467,913 788,345Income Taxes (Note 6)155,456 109,287 221,203Net Income632,497 358,626 567,142Less: Net Income Attributable to Noncontrolling Interest— (11,845) (27,425)Net Income Attributable to CONSOL Energy Inc. Shareholders$632,497 $346,781 $539,717Earnings Per Share (Note 1): Basic$2.79 $1.61 $2.99Dilutive$2.76 $1.60 $2.95Weighted Average Number of Common Shares Outstanding (Note 1): Basic226,680,369 214,920,561 180,693,243Dilutive229,003,599 217,037,804 182,821,136Dividends Paid Per Share$0.425 $0.400 $0.400The accompanying notes are an integral part of these financial statements.112CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(Dollars in thousands) December 31, 2011 December 31, 2010ASSETS Current Assets: Cash and Cash Equivalents$375,736 $32,794Accounts and Notes Receivable: Trade462,812 252,530Notes Receivable314,950 408Other Receivables105,708 21,181Accounts Receivable—Securitized (Note 9)— 200,000Inventories (Note 8)258,335 258,538Deferred Income Taxes (Note 6)141,083 174,171Recoverable Income Taxes— 32,528Prepaid Expenses239,353 142,856Total Current Assets1,897,977 1,115,006Property, Plant and Equipment (Note 10): Property, Plant and Equipment14,087,319 14,951,358Less—Accumulated Depreciation, Depletion and Amortization4,760,903 4,822,107Total Property, Plant and Equipment—Net9,326,416 10,129,251Other Assets: Deferred Income Taxes (Note 6)507,724 484,846Restricted Cash (Note 1)22,148 20,291Investment in Affiliates182,036 93,509Notes Receivable300,492 6,866Other288,907 220,841Total Other Assets1,301,307 826,353TOTAL ASSETS$12,525,700 $12,070,610The accompanying notes are an integral part of these financial statements.113CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(Dollars in thousands, except per share data) December 31, 2011 December 31, 2010LIABILITIES AND EQUITY Current Liabilities: Accounts Payable$522,003 $354,011Short-Term Notes Payable (Note 11)— 284,000Current Portion of Long-Term Debt (Note 13 and Note 14)20,691 24,783Accrued Income Taxes75,633 —Borrowings Under Securitization Facility (Note 9)— 200,000Other Accrued Liabilities (Note 12)770,070 801,991Total Current Liabilities1,388,397 1,664,785Long-Term Debt: Long-Term Debt (Note 13)3,122,234 3,128,736Capital Lease Obligations (Note 14)55,189 57,402Total Long-Term Debt3,177,423 3,186,138Deferred Credits and Other Liabilities: Postretirement Benefits Other Than Pensions (Note 15)3,059,671 3,077,390Pneumoconiosis Benefits (Note 16)173,553 173,616Mine Closing (Note 7)406,712 393,754Gas Well Closing (Note 7)124,051 130,978Workers’ Compensation (Note 16)151,034 148,314Salary Retirement (Note 15)269,069 161,173Reclamation (Note 7)39,969 53,839Other124,936 144,610Total Deferred Credits and Other Liabilities4,348,995 4,283,674TOTAL LIABILITIES8,914,815 9,134,597Stockholders’ Equity: Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 227,056,212Outstanding at December 31, 2011; 227,289,426 Issued and 226,162,133 Outstanding at December 31, 20102,273 2,273Capital in Excess of Par Value2,234,775 2,178,604Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding— —Retained Earnings2,184,737 1,680,597Accumulated Other Comprehensive Loss (Note 19)(801,554) (874,338)Common Stock in Treasury, at Cost—233,214 Shares at December 31, 2011 and 1,127,293 Shares atDecember 31, 2010(9,346) (42,659)Total CONSOL Energy Inc. Stockholders’ Equity3,610,885 2,944,477Noncontrolling Interest— (8,464)TOTAL EQUITY3,610,8852,936,013TOTAL LIABILITIES AND EQUITY$12,525,700 $12,070,610 The accompanying notes are an integral part of these financial statements.114CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY(Dollars in thousands, except per share data) CommonStock Capital inExcessof ParValue RetainedEarnings(Deficit) AccumulatedOtherComprehensiveIncome(Loss) CommonStock inTreasury TotalCONSOLEnergy Inc.Stockholders’Equity Non-ControllingInterest TotalEquityBalance at December 31, 2008$1,830 $993,478 $1,010,902 $(461,900) $(82,123) $1,462,187 $212,159 $1,674,346Net Income— — 539,717 — — 539,717 27,425 567,142Treasury Rate Lock (Net of $49 Tax)— — — (83) — (83) — (83)Gas Cash Flow Hedge (Net of $34,932 Tax)— — — (44,270) — (44,270) (8,862) (53,132)Actuarially Determined Long-Term LiabilityAdjustments (Net of $109,145 Tax)— — — (134,251) — (134,251) (298) (134,549)Comprehensive Income (Loss)— — 539,717 (178,604) — 361,113 18,265 379,378Issuance of Treasury Stock— — (21,429) — 15,831 (5,598) — (5,598)Issuance of CNX Gas Stock— — — — — — 157 157Tax Benefit from Stock-Based Compensation— 2,674 — — — 2,674 13 2,687Amortization of Stock-Based Compensation Awards— 32,723 — — — 32,723 16,658 49,381Stock-Based Compensation Awards to CNX GasEmployees— 4,741 — — — 4,741 (3,951) 790Net Change in Noncontrolling Interest— — — — — — (4,370) (4,370)Dividends ($0.40 per share)— — (72,292) — — (72,292) — (72,292)Balance at December 31, 20091,830 1,033,616 1,456,898 (640,504) (66,292) 1,785,548 238,931 2,024,479Net Income— — 346,781 — — 346,781 11,845 358,626Treasury Rate Lock (Net of $49 Tax)— — — (84) — (84) — (84)Gas Cash Flow Hedge (Net of $15,983 Tax)— — — (30,543) — (30,543) 5,252 (25,291)Actuarially Determined Long-Term LiabilityAdjustments (Net of $154,773 Tax)— — — (221,233) — (221,233) 5 (221,228)Purchase of CNX Gas Noncontrolling Interest— — — 18,026 — 18,026 — 18,026Comprehensive Income (Loss)— — 346,781 (233,834) — 112,947 17,102 130,049Issuance of Treasury Stock— — (37,221) — 23,633 (13,588) — (13,588)Issuance of Common Stock443 1,828,419 — — — 1,828,862 — 1,828,862Issuance of CNX Gas Stock— — — — — — 2,178 2,178Purchase of CNX Gas Noncontrolling Interest— (746,052) — — — (746,052) (263,008) (1,009,060)Tax Benefit from Stock-Based Compensation— 15,100 — — — 15,100 — 15,100Stock-Based Compensation Awards to CNX GasEmployees— 2,126 — — — 2,126 (1,771) 355Amortization of Stock-Based Compensation Awards— 45,395 — — — 45,395 2,198 47,593Net Change in Noncontrolling Interest— — — — — — (4,094) (4,094)Dividends ($0.40 per share)— — (85,861) — — (85,861) — (85,861)Balance at December 31, 20102,273 2,178,604 1,680,597 (874,338) (42,659) 2,944,477 (8,464) 2,936,013Net Income— — 632,497 — — 632,497 — 632,497Treasury Rate Lock (Net of $59 Tax)— — — (96) — (96) — (96)Gas Cash Flow Hedge (Net of $68,310 Tax)— — — 105,693 — 105,693 — 105,693Actuarially Determined Long-Term LiabilityAdjustments (Net of $1,583 Tax)— — — (32,813) — (32,813) — (32,813)Comprehensive Income (Loss)— — 632,497 72,784 — 705,281 — 705,281Issuance of Treasury Stock— — (32,001) — 33,313 1,312 — 1,312Tax Benefit from Stock-Based Compensation— 7,329 — — — 7,329 — 7,329Amortization of Stock-Based Compensation Awards— 48,842 — — — 48,842 — 48,842Net Change in Noncontrolling Interest— — — — — — 8,464 8,464Dividends ($0.425 per share)— — (96,356) — — (96,356) — (96,356)Balance at December 31, 2011$2,273 $2,234,775 $2,184,737 $(801,554) $(9,346) $3,610,885 $— $3,610,885The accompanying notes are an integral part of these financial statements.115CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(Dollars in thousands) For the Years Ended December 31, 2011 2010 2009Cash Flows from Operating Activities: Net Income$632,497 $358,626 $567,142Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities: Depreciation, Depletion and Amortization618,397 567,663 437,417Abandonment of Long-Lived Assets115,817 — —Stock-Based Compensation48,842 47,593 39,032Gain on Sale of Assets(46,497) (9,908) (15,121)Loss on Debt Extinguishment16,090 — —Amortization of Mineral Leases7,608 4,160 3,970Deferred Income Taxes(53,011) 17,029 47,430Equity in Earnings of Affiliates(24,663) (21,428) (15,707)Changes in Operating Assets: Accounts and Notes Receivable(83,770) (96,245) 84,597Inventories(380) 48,919 (79,787)Prepaid Expenses4,431 (20,974) 10,730Changes in Other Assets17,745 7,237 (724)Changes in Operating Liabilities: Accounts Payable144,652 78,839 (70,458)Other Operating Liabilities84,146 129,230 80,527Changes in Other Liabilities30,309 (15,443) (45,883)Other15,393 36,014 17,286Net Cash Provided by Operating Activities1,527,606 1,131,312 1,060,451Cash Flows from Investing Activities: Capital Expenditures(1,382,371) (1,154,024) (920,080)Acquisition of Dominion Exploration and Production Business— (3,470,212) —Purchase of CNX Gas Noncontrolling Interest— (991,034) —Proceeds from Sales of Assets747,971 59,844 69,884Distributions, net of Investments In, from Equity Affiliates55,876 11,452 4,855Net Cash Used in Investing Activities(578,524) (5,543,974) (845,341)Cash Flows from Financing Activities: Payments on Short-Term Borrowings(284,000) (188,850) (84,850)Payments on Miscellaneous Borrowings(11,627) (11,412) (19,190)(Payments on) Proceeds from Securitization Facility(200,000) 150,000 (115,000)Payments on Long-Term Notes, Including Redemption Premium(265,785) — —Proceeds from Issuance of Long-Term Notes250,000 2,750,000 —Tax Benefit from Stock-Based Compensation8,281 15,365 3,270Dividends Paid(96,356) (85,861) (72,292)Proceeds from Issuance of Common Stock— 1,828,862 —Issuance of Treasury Stock9,033 5,993 2,547Debt Issuance and Financing Fees(15,686) (84,248) —Noncontrolling Interest Member Distribution— — (2,500)Net Cash (Used In) Provided By Financing Activities(606,140) 4,379,849 (288,015)Net Increase (Decrease) in Cash and Cash Equivalents342,942 (32,813) (72,905)Cash and Cash Equivalents at Beginning of Period32,794 65,607 138,512Cash and Cash Equivalents at End of Period$375,736 $32,794 $65,607The accompanying notes are an integral part of these financial statements.116CONSOL ENERGY INC. AND SUBSIDIARIESNOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS(Dollars in thousands, except per share data)NOTE 1—SIGNIFICANT ACCOUNTING POLICIES:A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries (CONSOL Energy or the Company) is presented below.These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.Basis of Consolidation:The Consolidated Financial Statements include the accounts of majority-owned and controlled subsidiaries. Investments in business entities in whichCONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for underthe equity method. Investments in oil and gas producing entities are accounted for under the proportionate consolidation method. The accounts of variableinterest entities, where CONSOL Energy is the primary beneficiary, are included in the Consolidated Financial Statements. All significant intercompanytransactions and accounts have been eliminated in consolidation.Use of Estimates:The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requiresmanagement to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actualresults could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to businesscombinations, other postretirement benefits, coal workers' pneumoconiosis, workers' compensation, salary retirement benefits, stock-based compensation,asset retirement obligations, deferred income tax assets and liabilities, contingencies, and coal and gas reserve values.Cash and Cash Equivalents:Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with originalmaturities of three months or less.Trade Accounts Receivable:Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific accounts receivable whenit is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms ofsale, credit status of customers and various other circumstances. CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance asnecessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted andthe potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented. There were no material financingreceivables with a contractual maturity greater than one year.Inventories:Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventorycosts include labor, supplies, equipment costs, operating overhead and other related costs. The cost of merchandise for resale is determined by the last-in,first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. The cost of supplies inventory isdetermined by the average cost method and includes operating and maintenance supplies to be used in our coal and gas operations.Property, Plant and Equipment:Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment arecapitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required tomaintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs ofadditional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment areexpensed as incurred.Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore orminerals before beginning the development stage of the mine.117Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which arecosts incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel,construction of airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized. Asurface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and acommon ore body. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden in developing thefirst cut for mountain stripping or box cuts for surface stripping. Stripping costs incurred during the production phase of a mine are expensed as incurred.Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so thateach ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period.Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates areserve change is needed, or at a minimum once a year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortizationof development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the developmentphase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extractedduring the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future productionusing the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over proven and probable coalreserves. Advance mining royalties and leased coal interests are evaluated periodically, or at a minimum once a year, for impairment issues or whenever eventsor changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accountingestimates.When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profitor loss on disposition is recognized as gain or loss in other income.Gas well activity is accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory,development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory or development wells are expensed whensuch wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating theviability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and relatedequipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events andcircumstances indicate an adjustment is necessary, or at a minimum once a year; those revisions are accounted for prospectively as changes in accountingestimates.Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows: YearsBuildings and improvements 10 to 45Machinery and equipment 3 to 25Leasehold improvements Life of LeaseCosts to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimatedproven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipatedprocessing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstancesindicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an undergroundmine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period thechange occurs.Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economicbenefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtainingsoftware, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method overthe estimated useful life which does not exceed seven years.118Impairment of Long-lived Assets:Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated bythose assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measuredbased on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and theestimated fair value of the investment is less than the assets' carrying value. There was no impairment expense recognized for the year ended December 31,2011. Impairment expense of $1,813 and $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2010and 2009, respectively, for the impairment of sales contract assets previously acquired.Income Taxes:Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy'sfinancial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferredtaxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy'sassets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred taxassets when it is more likely than not that a deferred tax benefit will not be realized.CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustainedupon examination. For positions that do not meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit,determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement, is determined. A previously recognized taxposition is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. Theevaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and onvarious other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from othersources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution ofidentified matters.Restricted Cash:Restricted cash includes a $20,291 deposit into escrow as security to perfect CONSOL Energy's appeal to the Pennsylvania Environmental HearingBoard under the applicable statute related to the Ryerson dam litigation (See Note 24–Commitments and Contingent Liabilities for additional details.) Restrictedcash also includes a $1,857 deposit into escrow for maintenance of a leased office building. If the monies are unutilized at the end of the lease term then theywill be returned to CONSOL Energy.Postretirement Benefits Other Than Pensions:Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the HealthBenefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topicsof the FASB Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees' active serviceperiods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Postretirement benefitobligations established by the Health Benefit Act are treated as a multi-employer plan which requires expense to be recorded for the associated obligations aspayments are made.Pneumoconiosis Benefits and Workers' Compensation:CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependentsfor awards related to coal workers' pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers' compensation benefits foremployees who sustain employment related physical injuries or some types of occupational disease. Workers' compensation benefits include compensation fortheir disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions forestimated benefits are determined on an actuarial basis.Mine Closing, Reclamation and Gas Well Closing Costs:CONSOL Energy accrues for mine closing costs, reclamation costs, perpetual water care costs and dismantling and removing costs of gas relatedfacilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting StandardsCodification. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimateof fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset.Depreciation of the capitalized asset119retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally willescalate over the life of the producing asset, typically as production declines. Accretion is included in Cost of Goods Sold and Other Operating Charges on theConsolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, which includes treatment of water andthe reclamation of land upon exhaustion of coal and gas reserves.Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas related facilities are regularly reviewed bymanagement and are revised for changes in future estimated costs and regulatory requirements.Retirement Plans:CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirementplans. These plans are accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting StandardsCodification. The cost of these retiree benefits are recognized over the employees' service period. CONSOL Energy uses actuarial methods and assumptions inthe valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value ofobligations and plan assets are recognized through Other Comprehensive Income.Revenue Recognition:Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storagelocations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For gas sales, this occurs at the contractualpoint of delivery. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, river and dock, land andresearch and development, revenue is recognized generally as the service is provided to the customer.CONSOL Energy has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally usingthe sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.CONSOL Energy sells gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the sameday at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have beensimultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting StandardsCodification and are therefore reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.CONSOL Energy purchases gas produced by third parties at market prices less a fee. The gas purchased from third party producers is then resold toend users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Revenue and Purchased Gas Costs inthe Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when titlepasses to CONSOL Energy from the third party producer.Royalty Interest Gas Sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CONSOL Energy.Freight Revenue and Expense:Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense,respectively.Royalty Recognition:Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized.Royalty expenses for gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. These royalty expenses arepaid in cash in accordance with the terms of each agreement. Revenues for coal and gas sold related to production under royalty contracts, versus owned byCONSOL Energy, are recorded on a gross basis.120Contingencies:CONSOL Energy, or our subsidiaries, from time to time is subject to various lawsuits and claims with respect to such matters as personal injury,wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment andcontract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations havebeen incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and arebased upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted orreduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.Issuance of Common Stock:On March 31, 2010, CONSOL Energy issued 44,275,000 shares of common stock, which generated net proceeds of $1,828,862 to fund, in part, theacquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). The acquisitiontransaction closed on April 30, 2010. See Note 2–Acquisitions and Dispositions for further discussion of the Dominion Acquisition.Treasury Stock:On September 12, 2008, CONSOL Energy's Board of Directors announced a share repurchase program of up to $500,000 of the company's commonstock during a twenty-four month period beginning September 9, 2008, and ending September 8, 2010. There were no cash expenditures under the repurchaseprogram between January 1, 2009 and September 8, 2010. Shares of common stock repurchased by us are recorded at cost as treasury stock and result in areduction of stockholders' equity in our Consolidated Balance Sheets. From time to time, treasury shares may be reissued as part of our stock-basedcompensation programs. When shares are reissued, we use the weighted average cost method for determining cost. The difference between the cost of the sharesand the issuance price is added to or deducted from Capital in Excess of Par Value. Information regarding remaining treasury shares held by CONSOLEnergy is disclosed in the Consolidated Balance Sheets.Stock-Based Compensation:Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with theprovisions of Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on astraight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 18–Stock Based Compensation forfurther discussion.Earnings per Share:Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the reporting period. Dilutive earningsper share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares fromthe assumed exercise of stock options and performance stock options and the assumed vesting of restricted and performance stock units, if dilutive. Thenumber of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstandingrestricted and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the averagemarket price during the reporting period. CONSOL Energy includes the impact of pro forma deferred tax assets in determining potential windfalls andshortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the share-based awards that have beenexcluded from the computation of the diluted earnings per share because their effect would be anti-dilutive: For the Years Ended December 31, 2011 2010 2009Anti-Dilutive Options1,156,018 813,833 695,743Anti-Dilutive Restricted Stock Units— 1,960 5,274Anti-Dilutive Performance Share Units— — 41,581 1,156,018 815,793 742,598121 For the Years Ended December 31, 2011 2010 2009Net income attributable to CONSOL Energy Inc. shareholders$632,497 $346,781 $539,717Weighted average shares of common stock outstanding: Basic226,680,369 214,920,561 180,693,243Effect of stock-based compensation awards2,323,230 2,117,243 2,127,893Dilutive229,003,599 217,037,804 182,821,136Earnings per share: Basic$2.79 $1.61 $2.99Dilutive$2.76 $1.60 $2.95Shares of common stock outstanding were as follows: 2011 2010 2009Balance, beginning of year 226,162,133 181,086,267 180,549,851Issuance related to Stock-Based Compensation(1) 894,079 800,866 536,416Issuance of Common Stock(2) — 44,275,000 —Balance, end of year 227,056,212 226,162,133 181,086,267_________________(1) See Note 18–Stock-Based Compensation for additional information.(2) See Issuance of Common Stock in Note 1 for additional information.Accounting for Derivative Instruments:CONSOL Energy accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting StandardsCodification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) atfair value and record them in the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unlessspecial hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative arereported in other comprehensive income. The ineffective portions of hedges are recognized in earnings in the current period.CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsettingchanges in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge, or if a derivative ceases to be ahighly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.Accounting for Business Combinations:CONSOL Energy accounts for its business acquisitions under the acquisition method of accounting consistent with the requirements of the BusinessCombination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, basedon their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, and theutilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows andoutflows, discount rates and asset lives, among other items.122Recent Accounting Pronouncements:In December 2011, the Financial Accounting Standards Board issued an update to the Comprehensive Income Topic of the Accounting StandardsCodification intended to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported inother comprehensive income. This update allows entities to continue to report reclassifications out of accumulated other comprehensive income consistent withthe presentation requirements in effect before Update 2011-05. All other requirements included within Update 2011-05 are not affected and entities must reportcomprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. The effective date of this updateis for fiscal years, and interim periods within those years, beginning after December 15, 2011. We believe adoption of this new guidance will not have amaterial impact on CONSOL Energy's financial statements as these updates have an impact on presentation only.Subsequent Events:We have evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequentevents were identified.NOTE 2—ACQUISITIONS AND DISPOSITIONS:On October 21, 2011, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed a sale to HessOhio Developments, LLC (Hess) of 50% of its nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254,which are net of $5,719 transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreedto pay approximately $534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. Thenet gain on the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income.On September 30, 2011, CNX Gas Company completed a sale to Noble Energy, Inc. (Noble) of 50% of the Company's undivided interest in certainMarcellus Shale oil and gas properties in West Virginia and Pennsylvania covering approximately 628 thousand net acres and 50% of the Company'sundivided interest in certain of its existing Marcellus Shale wells and related leases. Cash proceeds of $485,464 were received related to this transaction,which are net of $34,998 transaction fees. Additionally, a note receivable has been recognized related to the two additional cash payments to be received on thefirst and a second anniversary of the transaction closing date. The discounted notes receivable of $311,754 and $296,344 have been recorded in Accountsand Notes Receivables—Notes Receivable and Other Assets—Notes Receivable, respectively. Subsequent to the transaction, an additional receivable of$16,703 and a payable of $980 were recorded for closing adjustments and have been included in Accounts and Notes Receivable - Other and AccountsPayable, respectively. The net loss on the transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income. As part ofthe transaction, CNX Gas also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling and completioncosts, up to approximately $2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub natural gas prices arebelow $4.00 per million British thermal units (MMBtu) for three consecutive months. The carry will remain suspended until average natural gas prices areabove $4.00/MMBtu for three consecutive months. Restrictions also include a $400,000 annual maximum on Noble's carried cost obligation.The following unaudited pro forma combined financial statements are based on CONSOL Energy's historical consolidated financial statements andadjusted to give effect to the September 30, 2011 sale of a 50% interest in certain Marcellus Shale assets. The unaudited pro forma results for the periodspresented below are prepared as if the transaction occurred as of January 1, 2010 and do not include material, non-recurring charges. Year Ended December 31, 2011 2010Total Revenue and Other Income $6,073,904 $5,212,597Earnings Before Income Taxes $775,807 $465,740Net Income Attributable to CONSOL Energy Inc.Shareholders $623,114 $345,169Basic Earnings Per Share $2.75 $1.60Dilutive Earnings Per Share $2.72 $1.59123The pro forma results are not necessarily indicative of what actually would have occurred if the transaction had been completed as of January 1, 2010,nor are they necessarily indicative of future consolidated results.On September 30 2011, CNX Gas Company and Noble formed CONE Gathering LLC (CONE), a joint venture established to develop and operate eachcompany's gas gathering system needs in the Marcellus Shale play. CNX Gas Company's 50% ownership interest in CONE is accounted for under the equitymethod of accounting. CNX Gas contributed its existing Marcellus Shale gathering infrastructure which had a net book value of $119,740 and Noblecontributed cash of approximately $67,545. CONE made a cash distribution to CNX Gas in the amount of $67,545. The cash proceeds have been recordedas cash inflows of $59,870 and $7,675 in Distributions from Equity Affiliates and Proceeds from the Sale of Assets, respectively, on the ConsolidatedStatements of Cash Flow. The gain on the transaction was $7,161 and was recognized in the Consolidated Statements of Income as Other Income.On September 21, 2011 CONSOL Energy entered into an agreement with Antero Resources Appalachian Corp. (Antero), pursuant to which CONSOLEnergy assigned to Antero overriding royalty interests (ORRI) of approximately 7% in approximately 116 thousand net acres of Marcellus Shale located in ninecounties in southwestern Pennsylvania and north central West Virginia, in exchange for $193,000. The net gain of $41,057 is included in Other Income in theConsolidated Statements of Income.In December 2010, CONSOL Energy completed a sale-leaseback of longwall shields for the McElroy Mine. Cash proceeds from the sale were $33,383,which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as anoperating lease. The lease term is five years.In September 2010, CONSOL Energy completed a sale-leaseback of longwall shields for the Enlow Fork Mine. Cash proceeds from the sale were$14,551, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted foras an operating lease. The lease term is five years.In June 2010, CONSOL Energy paid Yukon Pocahontas Coal Company $30,000 cash to acquire certain coal reserves and $20,000 cash in advancedroyalty payments recoupable against future production. Both payments were made per a settlement agreement in regards to the depositing of untreated waterfrom the Buchanan Mine, a mine operated by one of our subsidiaries, into the void spaces of the nearby mines of one of our other subsidiaries, Island CreekCoal Company.On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas Corporation (CNX Gas) outstanding common stock for a cash payment of$966,811 pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary of CONSOL Energy (CNXGas Acquisition). All of the shares of CNX Gas that were not already owned by CONSOL Energy were acquired at a price of $38.25 per share. CONSOLEnergy previously owned approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. An additional $24,223cash payment was made to cancel previously vested but unexercised CNX Gas stock options. CONSOL Energy financed the acquisition of CNX Gas sharesby means of internally generated funds, borrowings under its credit facilities and proceeds from its offering of common stock.On April 30, 2010, CONSOL Energy completed the acquisition of the Appalachian oil and gas exploration and production business of DominionResources, Inc. (Dominion Acquisition) for a cash payment of $3,470,212 which was principally allocated to oil & gas properties, wells and well-relatedequipment. The acquisition, which was accounted for under the acquisition method of accounting, included approximately 1 trillion cubic feet equivalents(Tcfe) of net proved reserves and 1.46 million net acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings wereapproximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia.Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition enhanced CONSOL Energy’sposition in the strategic Marcellus Shale fairway by increasing its development assets.The results of operations of the acquired entities are included in CONSOL Energy's Consolidated Statements of Income as of May 1, 2010. Net revenuesand net income (loss) resulting from the Dominion Acquisition that were included in CONSOL Energy's operating results were $133,850 and $(5,364),respectively, for the year ended December 31, 2010. 124The unaudited pro forma results for the year ended December 31, 2010, assuming the acquisition had occurred at January 1, 2010, are presented below.Pro forma adjustments include estimated operating results, transaction and financing fees incurred, additional interest related to the $2.75 billion of seniorunsecured notes and 44,275,000 shares of common stock issued in connection with the transaction. Year Ended December 31, 2010Total Revenue and Other Income $5,303,008Earnings Before Income Taxes $414,205Net Income Attributable to CONSOL Energy Inc. Shareholders $314,760Basic Earnings Per Share $1.39Dilutive Earnings Per Share $1.38The pro forma results are not necessarily indicative of what actually would have occurred if the Dominion Acquisition had been completed as of January1, 2010, nor are they necessarily indicative of future consolidated results.CONSOL Energy incurred $65,363 of acquisition-related costs as a direct result of the Dominion Acquisition and CNX Gas Acquisition for the yearended December 31, 2010. These expenses have been included within Transaction and Financing Fees on the Consolidated Statements of Income for the yearended December 31, 2010.In March 2010, CONSOL Energy completed the sale of the Jones Fork Mining Complex as part of a litigation settlement with Kentucky FuelCorporation. No cash proceeds were received and $10,482 of litigation settlement expense was recorded in Cost of Goods Sold and Other Operating Charges.The loss recorded was net of $8,700 related to the fair value of estimated amounts to be collected related to an overriding royalty on future mineable andmerchantable coal extracted and sold from the property.In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $10,499 in accordance with the Exit orDisposal Cost Obligations Topic of the FASB Accounting Standards Codification related to the Company's previous headquarters. This liability was recordedin Other Liabilities on the Consolidated Balance Sheets at December 31, 2009. Total expense related to this transaction was $12,500 which was recognized inCost of Goods Sold and Other Operating Charges. This amount included the fair value of the remaining lease payments of $10,974 as well as the removal of arelated asset of $1,526. Additionally, $5,832 was recognized in Other Income for the acceleration of a deferred gain associated with the initial sale-leasebackof the premises that occurred in 2005. In the year ended December 31, 2010, the cease use expense was reduced by $2,999 as a result of a change in estimatedcash flows.In August 2009, CONSOL Energy completed the lease assignment of CNX Gas' previous headquarters. Total expense related to this transaction for theyear ended December 31, 2010 was $1,500, which was recognized in Cost of Goods Sold and Other Operating Charges.In August 2009, CONSOL Energy completed a sale-leaseback of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, whichwas the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operatinglease. The lease term is five years.In July 2009, CONSOL Energy, through a subsidiary, leased approximately 20 thousand acres having Marcellus Shale potential from NiSource EnergyVentures, LLC, a subsidiary of Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in InvestingActivities on the Consolidated Statements of Cash Flow. The purchase price for the transaction was principally allocated to gas properties and relateddevelopment.In February 2009, CONSOL Energy completed a sale-leaseback of longwall shields for Bailey Mine. Cash proceeds for the sale were $42,282, whichwas the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operatinglease. The lease term is five years.125NOTE 3—OTHER INCOME: For the Years Ended December 31, 2011 2010 2009Gain on disposition of assets $46,497 $9,908 $15,121Equity in earnings of affiliates 24,663 21,428 15,707Royalty income 18,491 14,688 17,249Right-of-way issuance 13,519 122 31Service income 9,059 9,796 11,796Interest income 8,919 7,642 5,052Contract settlement — — 12,450Other 32,472 33,923 35,780 Total Other Income $153,620 $97,507 $113,186NOTE 4—INTEREST EXPENSE: For the Years Ended December 31, 2011 2010 2009Interest on debt $264,080 $213,832 $39,524Interest on other payables (189) 4,593 3,766Interest capitalized (15,547) (13,393) (11,871) Total Interest Expense $248,344 $205,032 $31,419Interest on other payables for the year ended December 31, 2011 includes a reversal of interest expense of $3,096 related to uncertain tax positions. See Note 6–Income Taxes for further discussion.NOTE 5—TAXES OTHER THAN INCOME: For the Years Ended December 31, 2011 2010 2009Production taxes $220,857 $202,536 $183,307Payroll taxes 59,186 54,631 48,702Property taxes 58,117 57,889 47,934Capital stock & franchise tax 3,670 11,201 8,895Virginia employment enhancement tax credit (6,109) (4,777) (3,715)Other 8,739 6,978 4,818 Total Taxes Other Than Income $344,460 $328,458 $289,941126NOTE 6—INCOME TAXES:Income taxes (benefits) provided on earnings consisted of: For The Years Ended December 31, 2011 2010 2009Current: U.S Federal$173,912 $82,031 $134,231U.S State34,555 13,652 41,482Non-U.S— (3,425) (1,940) 208,467 92,258 173,773Deferred: U.S. Federal(35,487) 8,463 49,672U.S. State(17,524) 8,566 (2,242) (53,011) 17,029 47,430Total Income Taxes$155,456 $109,287 $221,203The components of the net deferred tax assets are as follows: December 31, 2011 2010Deferred Tax Assets: Postretirement benefits other than pensions$1,217,246 $1,251,641Salary retirement103,146 65,309Mine closing95,193 144,131Pneumoconiosis benefits69,915 71,661Workers' compensation65,266 67,025Net operating loss57,669 58,428Alternative minimum tax54,998 141,758Mine subsidence41,453 34,659Capital lease24,763 27,918Reclamation23,738 31,177Other136,211 129,293Total Deferred Tax Assets1,889,598 2,023,000Valuation Allowance**(41,016) (62,668)Net Deferred Tax Assets1,848,582 1,960,332 Deferred Tax Liabilities: Property, plant and equipment(1,046,235) (1,221,362)Gas hedge(98,539) (29,209)Advance mining royalties(31,284) (31,574)Other(23,717) (19,170)Total Deferred Tax Liabilities(1,199,775) (1,301,315) Net Deferred Tax Assets$648,807 $659,017**Valuation allowance of ($41,016) has been allocated to long-term deferred tax assets for 2011. Valuation allowances of ($778) and ($61,890)have been allocated between current and long-term deferred tax assets respectively for 2010.127A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence,both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2011 and 2010, positive evidenceconsidered included financial and tax earnings generated over the past three years for certain subsidiaries, future income projections based on existing fixedprice contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various taxplanning strategies. Negative evidence included financial and tax losses generated by certain subsidiaries in prior periods and the inability to achieve forecastedresults at certain subsidiaries for those periods. CONSOL Energy continues to report, on an after federal tax basis, a deferred tax asset related to state operatinglosses of $57,669 with a related valuation allowance of $34,980 at December 31, 2011. The deferred tax asset related to state operating losses, on an afterfederal tax adjusted basis, was $58,428 with a related valuation allowance of $39,744 at December 31, 2010. A review of positive and negative evidenceregarding these state operating benefits concluded that a valuation allowance for various CONSOL Energy subsidiaries was warranted. The net operatinglosses expire at various times between 2012 and 2030.The deferred tax assets attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial andtax losses was also reviewed for positive and negative evidence regarding the realization of the deferred tax assets. A valuation allowance of $6,036 and$22,924 was recognized at December 31, 2011 and 2010, respectively. Included in the valuation allowance against the future deductible temporary differencesat December 31, 2011 and 2010, were $872 and $9,639 of allowances which were recognized through Other Comprehensive Income. These allowances relateto actuarial gains/losses for other postretirement, pension and long-term disability benefits that were recognized through Other Comprehensive Income.Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planningstrategies and may record adjustments to valuation allowances against deferred tax assets in future periods as appropriate that could materially impact netincome. During 2011, the deferred tax asset relating to alternative minimum tax decreased $86,760. This change was due to: $55,251 estimated utilizationrelating to 2011 activity, $25,687 utilization relating to the year 2010 accrual to return adjustment, and $5,823 utilization relating to the 2006-2007 auditsettlement.The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy'seffective tax rate: For the Years Ended December 31, 2011 2010 2009 Amount Percent Amount Percent Amount PercentStatutory U.S. federal income tax rate$275,784 35.0 % $163,770 35.0 % $275,921 35.0 %Excess tax depletion(91,470) (11.6) (70,812) (15.1) (68,787) (8.7)Effect of domestic production activities(22,209) (2.8) (5,633) (1.2) (12,707) (1.6)Federal and state tax accrual to tax returnreconciliation2,257 0.3 4,609 1.0 (1,256) (0.2)IRS and state tax examination settlements(5,188) (0.7) — — — —Net effect of state income taxes14,197 1.8 12,022 2.6 27,362 3.5Effect of releasing valuation allowance(22,618) (2.9) — — — —Effect of foreign tax(1,822) (0.2) (3,424) (0.7) (5,502) (0.7)Other6,525 0.8 8,755 1.8 6,172 0.8Income Tax Expense / Effective Rate$155,456 19.7 % $109,287 23.4 % $221,203 28.1 %128A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows: For the Years Ended December 31, 2011 2010Balance at beginning of period$91,349 $78,811Increase in unrecognized tax benefits resulting from tax positions taken during current period— 15,998Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior periods— (260)Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations(17,362) (3,200)Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities(36,401) —Balance at end of period$37,586 $91,349If these unrecognized tax benefits were recognized, $3,891 and $16,802 respectively would have affected CONSOL Energy's effective income tax ratefor the years ended December 31, 2011 and 2010, respectively.CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, theCompany is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2008. During theyear ended December 31, 2009, CONSOL Energy was advised by the Canadian Revenue Agency that its appeal of tax deficiencies paid as a result of theAgency's audit of the Company's Canadian tax returns filed for years 1997 through 2002 had been successfully resolved. The Company received a refund of$4,560 in 2010 as a result of the 2009 audit settlement recorded as a tax refund receivable in 2009.The IRS completed its audit of CONSOL Energy's income tax returns filed for 2006 and 2007. The Company concluded this examination and remittedpayment of the resulting tax deficiencies to federal and state taxing authorities before December 31, 2011. CONSOL paid $6,404 and $4,361 for tax years2006 and 2007, respectively. The IRS will commence its audit of tax years 2008 and 2009 in 2012. During the next year, the statute of limitations forassessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations forthese years is not expected to have a significant impact on CONSOL Energy's total uncertain income tax positions and net income for the twelve-month period.CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2011 and 2010, the Companyhad an accrued liability of $5,373 and $10,774 respectively, for interest related to uncertain tax positions. Interest expense related to unrecognized tax benefitswas ($3,096), $2,436 and $2,409 that were recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2011, 2010 and2009, respectively. Interest expense was reduced during the year ended December 31, 2011 due to the reversal of various uncertain tax liabilities primarily dueto the expiration of statutes. During the year ended December 31, 2011, CONSOL Energy paid $1,633 and $673 of interest related to income tax deficienciesfor tax years 2006 and 2007 with the IRS.CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2011 and 2010, therewere no accrued penalties recognized.129NOTE 7—MINE CLOSING, RECLAMATION & GAS WELL CLOSING:CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilitiesusing the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification.CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulateddepreciation. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on theConsolidated Balance Sheets.The reconciliation of changes in the asset retirement obligations at December 31, 2011 and 2010 is as follows: As of December 31, 2011 2010Balance at beginning of period $670,856 $533,177Accretion expense 48,120 46,200Payments (57,584) (45,961)Revisions in estimated cash flows (4,621) 82,742Dominion Acquisition (Note 2) — 62,098Disposition (6,698) (7,400)Balance at end of period $650,073 $670,856For the year ended December 31, 2010, Revisions in estimated cash flows include $80,525 related to additional reclamation liabilities recognized at theFola 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 was revised.For the year ended December 31, 2011, Other includes ($6,698) for asset dispositions related to the sale of the Bishop mining operation. For the yearended December 31, 2010, Other includes ($7,400) for asset dispositions related to the sale of Jones Fork Mining Complex. See Note 2–Acquisitions andDispositions for additional details.NOTE 8—INVENTORIES:Inventory components consist of the following: December 31, 2011 2010Coal$105,378 $108,694Merchandise for resale43,639 50,120Supplies109,318 99,724Total Inventories$258,335 $258,538Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories overcarrying LIFO value was $22,406 and $19,624 at December 31, 2011 and December 31, 2010, respectively.NOTE 9—ACCOUNTS RECEIVABLE SECURITIZATION:CONSOL Energy and certain of our U.S. subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on acontinuous basis of eligible trade accounts receivable. The facility allows CONSOL Energy to receive on a revolving basis up to $200,000. The facility alsoallows for the issuance of letters of credit against the $200,000 capacity. At December 31, 2011, there were no letters of credit outstanding against the facility.CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated bycertain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell allof their eligible trade accounts receivable to CNX Funding Corporation, who in turn sells these receivables to financial institutions and their affiliates, whilemaintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes ReceivableTrade in the Consolidated Balance Sheets, is recorded at fair value. Due to a short average collection cycle for such receivables, our130collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retainedinterest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for thefinancial institutions for a fee based upon market rates for similar services.In accordance with the Transfers and Servicing Topic of the FASB Accounting Standards Codification, CONSOL Energy records transactions underthe securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral is reported as Accounts Receivable - Securitizedand the borrowings are classified as debt in Borrowings under Securitization Facility.The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions.Costs associated with the receivables facility totaled $1,986, $2,676 and $2,990 for the years ended December 31, 2011, 2010 and 2009, respectively.These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements ofIncome. The receivables facility expires in April 2012.At December 31, 2011 and 2010, eligible accounts receivable totaled $192,700 and $200,000, respectively. There was subordinated retained interest of$192,700 at December 31, 2011 and there was no subordinated retained interest at December 31, 2010. There were no borrowings under the securitizationfacility recorded on the Consolidated Balance Sheets at December 31, 2011. Accounts Receivable - Securitization and Borrowings under Securitization Facilityof $200,000 were recorded on the Consolidated Balance Sheets at December 31, 2010. Also, a $200,000 decrease, $150,000 increase and $115,000 decrease inthe accounts receivable securitization facility for the years ended December 31, 2011, 2010 and 2009, respectively, are reflected in the Net Cash (Used In)Provided By Financing Activities in the Consolidated Statements of Cash Flows. In accordance with the facility agreement, the Company is able to receiveproceeds based upon the eligible accounts receivable at the previous month end.NOTE 10—PROPERTY, PLANT AND EQUIPMENT: December 31, 2011 2010Coal and other plant and equipment$5,160,759 $5,100,085Proven gas properties1,542,837 1,662,605Coal properties and surface lands1,340,757 1,292,701Intangible drilling cost1,277,678 1,116,884Unproven gas properties1,258,027 2,206,399Gas gathering equipment963,494 941,772Airshafts659,736 662,315Leased coal lands540,817 536,603Mine development457,179 587,518Gas wells and related equipment408,814 367,448Coal advance mining royalties393,340 389,379Other gas assets79,816 84,571Gas advance royalties4,065 3,078Total property, plant and equipment14,087,319 14,951,358Less Accumulated depreciation, depletion and amortization4,760,903 4,822,107Total Net Property, Plant and Equipment$9,326,416 $10,129,251Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms generally are extendedautomatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights asfee ownership for mineral extraction, and are legally considered real property interests. We also make advance payments (advanced mining royalties) to lessorsunder certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or apercentage of gross realization from the sale of the coal. We evaluate our properties periodically for impairment issues or whenever events or circumstancesindicate that the carrying amount may not be recoverable.131Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to themine. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate areserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is placed into production. At an undergroundmine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period thechange occurs.Amortization of capitalized mine development costs associated with a coal reserve is computed on a units-of-production basis as the coal is produced sothat each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particularperiod. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available thatindicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the changeoccurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the endof the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantiallycomplete. Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into theproduction phase.Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells,development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory or development wells are expensed whensuch wells are determined to be non-productive. Also, if an exploratory well has found sufficient quantities of reserves but the determination is subsequentlymade that the related project is no longer viable, the exploratory well is expensed. The costs of producing properties and mineral interests are amortized usingthe units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-productionamortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted forprospectively as changes in accounting estimates. Any material effect from changes in estimates is disclosed in the period the change occurs.The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yetcommenced or have ceased, and therefore, are not being amortized for the years ended December 31, 2011 and 2010, respectively. December 31, 2011 2010Unproven gas properties $1,258,027 $2,206,399Coal properties 386,402 394,635Leased coal lands 178,988 171,056Mine development 78,990 34,907Coal advance mining royalties 54,533 67,674Airshafts 47,437 73,703Gas advance royalties 3,884 2,800 Total $2,008,261 $2,951,174As of December 31, 2011 and 2010, plant and equipment includes gross assets under capital lease of $95,995 and $88,859, respectively. For theyears ended December 31, 2011 and 2010, the Gas segment maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gasgathering equipment. For the years ended December 31, 2011 and 2010, the Gas segment also maintains a capital lease for vehicles of $8,664 and $5,919,respectively, which are included in Other gas assets. For the years ended December 31, 2011 and 2010, the All Other segment maintains capital leases forvehicles and computer equipment of $20,412 and $16,021, respectively, which are included in Coal and other plant and equipment. Accumulatedamortization for capital leases was $39,854 and $30,251 at December 31, 2011 and 2010, respectively. Amortization expense for capital leases is included inDepreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 14–Leases for further discussion of capital leases.Long-Lived Asset AbandonmentIn June 2011, CONSOL Energy decided to permanently close its Mine 84 mining operation located near Washington, PA. This decision was part ofCONSOL Energy's ongoing effort to reallocate resources into more profitable coal operations and Marcellus Shale drilling operations. The closure decisionresulted in the recognition of an abandonment expense of $115,817132for the year ended December 31, 2011. The abandonment expense resulted from the removal of the June 30, 2011 carrying value of the following Mine 84related assets from the Consolidated Balance Sheets: Mine development - $92,136, Airshafts - $15,352, Coal equipment - $2,080, Inventories - $757, andPrepaid Expenses - $385. Additionally, the Mine 84 abandonment expense also includes the recognition of a Mine Closing expense of $5,107. The effect onnet income of the Mine 84 abandonment was $75,281 of expense for the year ended December 31, 2011. The impact to basic and dilutive earnings per sharewas $0.33 for the year ended December 31, 2011.Industry Participation AgreementsIn 2011, CONSOL Energy entered into two significant industry participation agreements (also referred to as "joint ventures" or "JVs") that provideddrilling and completion carries for our retained interests. The following table provides information about our industry participation agreements as of December31, 2011: Industry Industry Drilling Participation Participation Total Carries DrillingShale Agreement Agreement Drilling Billed to CarriesPlay Partner Date Carries Partner RemainingMarcellus Noble September 30, 2011 $2,100,000 $10,180 $2,089,820Utica Hess October 21, 2011 $534,000 $1,200 $532,800NOTE 11—SHORT-TERM NOTES PAYABLE:On April 12, 2011, CONSOL Energy amended and extended its $1,500,000 Senior Secured Credit Agreement through April 12, 2016. The previousfacility was set to expire on May 7, 2014. The amendment provides more favorable pricing and the facility continues to be secured by substantially all of theassets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1,500,000 of borrowings and letters of credit.CONSOL Energy can request an additional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio offinancial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. Thefacility includes a minimum interest coverage ratio covenant of no less than 2.50 to 1.00, measured quarterly. The interest coverage ratio was 5.80 to 1.00 atDecember 31, 2011. The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The leverage ratio was 2.15to 1.00 at December 31, 2011. The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The seniorsecured leverage ratio was 0.19 to 1.00 at December 31, 2011. Affirmative and negative covenants in the facility limit our ability to dispose of assets, makeinvestments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with another corporation and amend, modify or restate the seniorunsecured notes. At December 31, 2011, the $1,500,000 facility had no borrowings outstanding and $265,673 of letters of credit outstanding, leaving$1,234,327 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2010, the $1,500,000 facility had $155,000 ofborrowings outstanding and $266,656 of letters of credit outstanding, leaving $1,078,344 of capacity available for borrowings and the issuance of letters ofcredit. The facility bore a weighted average interest rate of 3.76% at December 31, 2010.On April 12, 2011, CNX Gas entered into a $1,000,000 Senior Secured Credit Agreement which extends until April 12, 2016. It replaced the $700,000Senior Secured Credit Facility which was set to expire on May 6, 2014. The replacement facility provides more favorable pricing and the facility continues tobe secured by substantially all of the assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 for borrowings and lettersof credit. CNX Gas can request an additional $250,000 increase in the aggregate borrowing limit amount. The facility was increased to meet the assetdevelopment needs of the company. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in thefacility limit CNX Gas’ ability to dispose of assets, make investments, pay dividends and merge with another corporation. An amendment to the creditagreement was approved by the lenders and became effective December 14, 2011. The amendment allows unlimited investments in joint ventures for thedevelopment and operation of gas gathering systems and provides for $600,000 of loans, advances, and dividends from CNX Gas to CONSOL Energy.Investments in the CONE Gathering Company (See Note 27–Related Party Transactions) are unrestricted under this amendment. The facility includes amaximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.00 to 1.00 at December 31, 2011. The facilityalso includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 34.18 to 1.00 at December 31, 2011.At December 31, 2011, the $1,000,000 facility had no borrowings outstanding and $70,203 of letters of credit outstanding, leaving $929,797 of capacityavailable for borrowings and the issuance of letters of credit. At December 31, 2010, the $700,000 facility had $129,000 of borrowings outstanding and133$70,203 of letters of credit outstanding, leaving $500,797 of capacity available for borrowings and the issuance of letters of credit. The facility bore aweighted average interest rate of 2.26% as of December 31, 2010.NOTE 12—OTHER ACCRUED LIABILITIES: December 31, 2011 2010Subsidence liability $108,094 $83,751Accrued payroll and benefits 65,775 58,771Accrued interest 63,577 64,695Accrued other taxes 50,869 56,839Short-term incentive compensation 37,947 38,474Uncertain income tax positions (See Note 6) 6,820 41,235Other 128,247 139,079Current portion of long-term liabilities: Postretirement benefits other than pensions 182,529 179,809Mine closing 34,501 38,433Workers' compensation 24,837 27,754Gas well closing 24,660 27,919Reclamation 20,180 25,933Pneumoconiosis benefits 10,027 10,915Long-term disability 6,294 6,126Salary retirement 5,713 2,258Total Other Accrued Liabilities $770,070 $801,991NOTE 13—LONG-TERM DEBT: December 31, 2011 2010Debt: Senior notes due April 2017 at 8.00%, issued at par value$1,500,000 $1,500,000Senior notes due April 2020 at 8.25%, issued at par value1,250,000 1,250,000Senior notes due March 2021 at 6.375%, issued at par value250,000 —Senior secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of$242 at December 31, 2010)— 249,758Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%102,865 102,865Advance royalty commitments (6.73% and 7.56% weighted average interest rate for December 31, 2011and 2010, respectively)31,053 32,211Note Due December 2012 at 6.10%— 10,438Other long-term notes maturing at various dates through 203175 93 3,133,993 3,145,365Less amounts due in one year11,759 16,629Long-Term Debt$3,122,234 $3,128,736134Annual undiscounted maturities on long-term debt during the next five years are as follows:Year ended December 31,Amount2012$11,75920133,27520143,00420152,73220162,555Thereafter3,110,668 Total Long-Term Debt Maturities$3,133,993On March 9, 2011 CONSOL Energy closed the offering of $250,000 of 6.375% senior notes which mature on March 1, 2021. The notes areguaranteed by substantially all of our existing wholly owned domestic subsidiaries.On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250,000, 7.875% senior secured notes due March 1, 2012 in accordance withthe terms of the indenture governing these notes. The redemption price included principal of $250,000, a make-whole premium of $15,785 and accruedinterest of $2,188 for a total redemption cost of $267,973. The loss on extinguishment of debt was $16,090, which primarily represents the interest thatwould have been paid on these notes if held to maturity.In August 2011, CONSOL Energy paid the remaining principal balance on the 6.10% Notes due December 2012. The early debt retirement wascompleted as a condition of a drilling services contract termination with a variable interest entity.Transaction and financing fees of $14,907 were incurred during the year ended December 31, 2011 related to the solicitation of consents from theholders 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 consentsallowed an amendment of the indentures for each of those notes, clarifying that the joint venture transactions with Noble and Hess were permissible underthose indentures. See Note 2–Acquisitions and Dispositions for additional information.NOTE 14—LEASES:CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases,together with the present value of the net minimum capital lease payments, at December 31, 2011, are as follows: Capital Operating Leases LeasesYear Ended December 31, 2012 $13,179 $88,5022013 11,417 82,5682014 10,037 69,7022015 8,406 57,4182016 7,444 37,769Thereafter 35,667 149,771Total minimum lease payments $86,150 $485,730Less amount representing interest (0.75% – 7.36%) 22,029 Present value of minimum lease payments 64,121 Less amount due in one year 8,932 Total Long-Term Capital Lease Obligation $55,189 Rental expense under operating leases was $111,861, $94,137, and $77,960 for the years ended December 31, 2011, 2010 and 2009, respectively.135NOTE 15—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. Thebenefits for these plans are based primarily on years of service and employee's pay near retirement. CONSOL Energy's salaried plan allows for lump-sumdistributions of benefits earned up until December 31, 2005, at the employees' election. The Restoration Plan was frozen effective December 31, 2006 and wasreplaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy's Restoration Plan allows only for lump-sum distributionsearned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas. TheSupplemental Retirement Plan was frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL EnergyDefined Contribution Restoration Plan.In March of 2009, the CNX Gas defined benefit retirement plan was merged into the CONSOL Energy's non-contributory defined benefit retirementplan. At the time, the change did not impact the benefits for employees of CNX Gas. However, during 2010 an amendment was adopted to recognize pastservice at CNX Gas to current employees of CNX Gas who opted out of the plan for additional company contributions into their defined contribution plan andextend coverage to employees previously not eligible to participate in this plan.Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry RetireeHealth Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networksand coordination with Medicare. For salaried employees hired before January 1, 2007, the eligibility requirement is either age 55 with 20 years of service or age62 with 15 years of service. Also, salaried employees and retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher,dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared byCONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility ofthe participants. Any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007 or later will not become eligible forretiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medicalspending allowance of $2,250 per year for each year of service at retirement. Newly employed inexperienced employees represented by the United MineWorkers of America (UMWA), hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive adefined contribution benefit of $1 per each hour worked through December 31, 2013, increasing to $1.50 per hour worked effective January 1, 2014 throughDecember 31, 2016.For the year ended December 31, 2011 CONSOL Energy received proceeds of $7,973 under the Patient Protection and Affordable Care Act (PPACA)related to reimbursement from the Federal Government for retiree health spending. This amount is included as a reduction of benefit and other payments in thereconciliation of changes in benefit obligation. There is no guarantee that additional proceeds will be received under this program.The OPEB liability reflects an increase of $11,800 and $12,300 as of December 31, 2011 and 2010, respectively, due to the PPACA reform legislation;in particular, the estimated impact of the potential excise tax beginning in 2018. A corresponding increase in Other Comprehensive Loss was also recognized.The estimated increase in the liability was calculated using the following assumptions: testing pre-Medicare and Medicare covered retirees on a combinedbasis; assuming individual participants have an average 2012 claim cost and future healthcare trend assumptions equal to those used in the year endvaluation; assuming the 2018 tax threshold amount to increase for inflation in later years. These assumptions may change once additional guidance becomesavailable.The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2011 and 2010, is as follows:136 Pension Benefits Other Postretirement Benefits at December 31, at December 31, 2011 2010 2011 2010Change in benefit obligation: Benefit obligation at beginning of period $701,152 $654,022 $3,257,199 $2,844,093Service cost 17,457 14,491 13,677 13,147Interest cost 37,744 37,150 179,739 162,815Actuarial loss (gain) 159,320 54,006 (51,650) 400,118Plan amendments (7,186) 682 — 204Dominion Acquisition — 900 — 2,800Participant contributions — — 6,088 4,802Benefits and other payments (51,135) (60,099) (162,853) (170,780)Benefit obligation at end of period $857,352 $701,152 $3,242,200 $3,257,199 Change in plan assets: Fair value of plan assets at beginning of period $537,721 $462,000 $— $—Actual return on plan assets 23,791 63,444 — —Company contributions 72,194 72,376 156,765 165,978Participant contributions — — 6,088 4,802Benefits and other payments (51,135) (60,099) (162,853) (170,780)Fair value of plan assets at end of period $582,571 $537,721 $— $— Funded status: Current liabilities $(5,713) $(2,258) $(182,529) $(179,809)Noncurrent liabilities (269,069) (161,173) (3,059,671) (3,077,390)Net obligation recognized $(274,782) $(163,431) $(3,242,200) $(3,257,199) Amounts recognized in accumulated other comprehensiveincome consist of: Net actuarial loss $494,622 $358,674 $1,328,077 $1,485,090Prior service credit (8,244) (1,725) (75,546) (121,943)Net amount recognized (before tax effect) $486,378 $356,949 $1,252,531 $1,363,147137The components of net periodic benefit costs are as follows: Pension Benefits Other Postretirement Benefits For the Years Ended December 31, For the Years Ended December 31, 2011 2010 2009 2011 2010 2009Components of net periodic benefit cost: Service cost$17,457 $14,485 $12,332 $13,677 $13,147 $12,654Interest cost37,744 37,150 35,483 179,739 162,815 151,451Expected return on plan assets(38,522) (36,977) (36,631) — — —Amortization of prior service cost (credits)(666) (735) (1,109) (46,397) (46,415) (46,415)Recognized net actuarial loss38,102 31,870 22,263 105,364 70,145 50,357Benefit cost$54,115 $45,793 $32,338 $252,383 $199,692 $168,047Amounts included in accumulated other comprehensive loss, expected to be recognized in 2012 net periodic benefit costs: Other Pension Postretirement Benefits BenefitsPrior Service cost (benefit) recognition $(1,630) $(46,397)Actuarial loss recognition $49,049 $81,380The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets: As of December 31, 2011 2010Projected benefit obligation $857,352 $701,152Accumulated benefit obligation $782,820 $629,433Fair value of plan assets $582,571 $537,721Assumptions:The weighted-average assumptions used to determine benefit obligations are as follows: Pension Benefits Other Postretirement Benefits For the Year Ended For the Year Ended December 31, December 31, 2011 2010 2011 2010Discount rate 4.50% 5.30% 4.51% 5.33%Rate of compensation increase 3.77% 3.68% — —The weighted-average assumptions used to determine net periodic benefit costs are as follows: Pension Benefits at Other Postretirement Benefits at December 31, December 31, 2011 2010 2009 2011 2010 2009Discount rate 5.30% 5.79% 6.28% 5.33% 5.87% 6.20%Expected long-term return on plan assets 8.00% 8.00% 8.00% — — —Rate of compensation increase 3.66% 4.14% 4.05% — — —138The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted forexpected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and adistribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to producethe expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. Thesereturns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.The assumed health care cost trend rates are as follows: At December 31, 2011 2010 2009Health care cost trend rate for next year 6.85% 8.47% 8.74%Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.50% 4.50% 4.50%Year that the rate reaches ultimate trend rate 2026 2023 2023Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumedhealth care cost trend rates would have the following effects: 1-Percentage 1-Percentage Point Increase Point DecreaseEffect on total of service and interest cost components $24,909 $(20,876)Effect on accumulated postretirement benefit obligation $410,191 $(349,038)Assumed discount rates also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage pointchange in assumed discount rate would have the following effect on benefit costs: 0.25 Percentage 0.25 Percentage Point Increase Point DecreasePension benefit costs (decrease) increase $(1,948) $1,965Other postemployment benefits costs (decrease) increase $(4,666) $5,543Plan Assets:The company's overall investment strategy is to meet current and future benefit payment needs through diversification across asset classes, fundstrategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation.The target allocations for plan assets are 36 percent U.S. equity securities, 24 percent non-U.S. equity securities and 40 percent fixed income. Both the equityand fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Common CollectiveTrusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed andemerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed incomeportfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The average quality of the fixed income portfolio must berated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily acrossvarious strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust's liabilities in order to reduce the volatilityresulting from the risk of changes in interest rates and the impact of such changes on the Trust's overall financial status. Derivatives, interest rate swaps,options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however theymay not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other comingled vehicles so long as the pooledinvestment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management and/or oversight by anInvestment Advisor registered with the SEC. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investmentprogram on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoingappropriateness of the overall investment policy.139The fair values of plan assets at December 31, 2011 and 2010 by asset category are as follows: Fair Value Measurements at December 31, 2011 Fair Value Measurements at December 31, 2010 Quoted Quoted Prices in Prices in Active Active Markets for Significant Significant Markets for Significant Significant Identical Observable Unobservable Identical Observable Unobservable Assets Inputs Inputs Assets Inputs Inputs Total (Level 1) (Level 2) (Level 3) Total (Level 1) (Level 2) (Level 3)Asset Category Cash/Accrued Income $552 $552 $— $— $482 $482 $— $—US Equities (a) 11 11 — — 2 2 — —MGI Collective Trusts US Large Cap Growth Equity (b) 46,670 — 46,670 — 48,328 — 48,328 —US Large Cap Value Equity (c) 48,115 — 48,115 — 48,802 — 48,802 —US Small/Mid Cap Growth Equity(d) 20,897 — 20,897 — 20,580 — 20,580 —US Small/Mid Cap Value Equity (e) 21,375 — 21,375 — 20,459 — 20,459 —US Core Fixed Income (f) 29,881 — 29,881 — 27,660 — 27,660 —Non-US Core Equity (g) 139,395 — 139,395 — 130,305 — 130,305 —US Long Duration Investment GradeFixed Income (h) 35,709 — 35,709 — 46,848 — 46,848 —US Long Duration Fixed Income (i) 34,434 — 34,434 — 67,949 — 67,949 —US Large Cap Passive Equity (j) 71,786 — 71,786 — 59,776 — 59,776 —US Passive Fixed Income (k) 16,158 — 16,158 — 14,996 — 14,996 —US Long Duration Passive FixedIncome (l) 21,422 — 21,422 — 26,796 — 26,796 —US Ultra Long Duration FixedIncome (m) 33,466 — 33,466 — 24,738 — 24,738 —US Active Long CorporateInvestment (n) 62,700 — 62,700 — — — — —Total $582,571 $563 $582,008 $— $537,721 $484 $537,237 $—__________(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. Ittargets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary activemanagers 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 diversificationacross economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying riskcharacteristics. Fund selection and allocations within the portfolio are implemented by MGI's investment management team. The strategy isbenchmarked 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 broaddiversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers withvarying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI's investment management team. The smallercap 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 diversificationacross economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying riskcharacteristics. Fund selection and allocations within the portfolio are implemented by MGI's investment management team. The smaller cap orientationof the strategy requires the investment140team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500Value Index.(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 achievelower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targetedto 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 yieldand exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by MGI's investmentmanagement 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 diversificationacross economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying riskcharacteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through othernon-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by MGI's investment management team. The strategy isbenchmarked 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 termliquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% tothe 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. Thestrategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fundselection and allocations within the portfolio are implemented by MGI's investment management team. The strategy is benchmarked to the BarclaysCapital 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 passiveinvestments 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 durationportfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps withsequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in noleverage. 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 monthLIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets tothe 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. Itseeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through activemanagement while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the BarclaysCapital U.S. Long Corporate Index and 10% to the Barclay's Capital Long Treasury.There are no investments in CONSOL Energy stock held by these plans at December 31, 2011 or 2010.There are no assets in the other postretirement benefit plans at December 31, 2011 or 2010.141Cash Flows:CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns heldin the trust, we expect to contribute $110 million to our pension plan trust in 2012. Pension benefit payments are primarily funded from the trust. CONSOLEnergy does not expect to contribute to the other postemployment plan in 2011. We intend to pay benefit claims as they are due.The following benefit payments, reflecting expected future service, are expected to be paid: Other Pension Postretirement Benefits Benefits2012 $50,778 $182,5292013 $50,902 $187,6062014 $51,922 $191,4292015 $53,247 $194,9952016 $56,114 $198,422Year 2017-2021 $293,606 $989,306NOTE 16—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits toemployees and their dependents resulting from occurrences of coal workers' pneumoconiosis disease. CONSOL Energy is also responsible under various statestatutes for pneumoconiosis benefits. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarialpresent value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries. The calculation is based onassumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates. These assumptions arederived from actual company experience and outside sources. Actuarial gains associated with CWP have resulted from numerous legislative changes overmany years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted fromlower incident rates and lower severity of claims filed than our assumptions originally reflected.The CWP liability was remeasured as of April 1, 2010 due to new legislation enacted in the Patient Protection and Affordable Care Act (PPACA). Ingeneral, the PPACA impacts CONSOL Energy's liability in that future claims will be approved at a higher rate than has occurred in the past. The PPACAmade two changes to the Federal Black Lung Benefits Act (FBLBA). First, it provided changes to the legal criteria used to assess and award claims by creatinga legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and sufferfrom a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the diseasewas not caused at his/her work. Second, it changed the law so black lung benefits will continue to be paid to dependent survivors when the miner passesaway, regardless of the cause of the miner's death. The impact of the new law increased CONSOL Energy's CWP liability by $45,700. The law changeincreased expense by $6,658 for the year ended December 31, 2010. In conjunction with the law change, CONSOL Energy conducted an extensive experiencestudy regarding the rate of claim incidence. Based on historical company data and available industry data, with emphasis on recent history, certainassumptions were revised at the remeasurement date. Most notably, the expected number of claims, prior to the law change, was reduced to more appropriatelyreflect CONSOL Energy's historical experience. The assumption and remeasurement changes resulted in a decrease in the liability of $47,700. Theassumption and remeasurement changes reduced expense by $10,576 for the year ended December 31, 2010.The combined impact of the changes in actuarial assumptions, remeasurement and changes to the FBLBA was a net decrease of $1,232 in liability, netof $768 tax, as well as Accumulated Other Comprehensive Income based on an April 1, 2010 remeasurement date. The combined impact of these changesreduced expense by $3,918 for the year ended December 31, 2010.CONSOL Energy is also responsible to compensate individuals who sustain employment related physical injuries or some types of occupationaldiseases and, on some occasions, for costs of their rehabilitation. Workers' compensation laws will also compensate survivors of workers who sufferemployment related deaths. Workers' compensation laws are administered by state agencies with each state having its own set of rules and regulationsregarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims througha self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers' compensation obligation calculated by independentactuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions. The assumptionsinclude discount rate, future healthcare trend rate, benefit duration and recurrence of injuries.142Actuarial gains associated with workers' compensation have resulted from discount rate changes, several years of favorable claims experience, variousfavorable state legislation changes and overall lower incident rates than our assumptions. CWP Workers' Compensation at December 31, at December 31, 2011 2010 2011 2010Change in benefit obligation: Benefit obligation at beginning of period $184,531 $194,641 $174,456 $179,268State administrative fees and insurance bond premiums — — 7,035 7,816Service, legal and administrative cost 7,620 8,067 20,015 30,399Interest cost 9,330 10,789 8,238 9,156Actuarial gain (6,783) (17,381) (2,783) (14,553)Benefits paid (11,118) (11,585) (32,892) (37,630)Benefit obligation at end of period $183,580 $184,531 $174,069 $174,456 Current liabilities $(10,027) $(10,915) $(24,837) $(27,754)Noncurrent liabilities (173,553) (173,616) (149,232) (146,702)Net obligation recognized $(183,580) $(184,531) $(174,069) $(174,456) Amounts recognized in accumulated other comprehensiveincome consist of: Net actuarial gain $(164,374) $(178,772) $(55,233) $(56,358)Prior service credit (395) (1,123) — —Net amount recognized (before tax effect) $(164,769) $(179,895) $(55,233) $(56,358)The components of the net periodic cost (credit) are as follows: CWP Workers’ Compensation For the Years Ended For the Years Ended December 31, December 31, 2011 2010 2009 2011 2010 2009Service cost$4,620 $5,067 $7,074 $17,872 $27,015 $28,394Interest cost9,330 10,789 12,054 8,238 9,156 8,765Legal and administrative costs3,000 3,000 2,700 2,143 3,384 3,401Amortization of prior service cost(728) (728) (728) — — —Recognized net actuarial gain(21,182) (21,585) (19,590) (3,907) (3,072) (4,200)State administrative fees and insurance bond premiums— — — 7,035 7,816 6,710Net periodic cost (credit)$(4,960) $(3,457) $1,510 $31,381 $44,299 $43,070143Amounts included in accumulated other comprehensive income, expected to be recognized in 2012 net periodic benefit costs: Workers' CWP Compensation Benefits BenefitsPrior Service benefit recognition $(395) $—Actuarial gain recognition $(19,338) $(3,944)Assumptions:The weighted-average discount rate used to determine benefit obligations and net periodic (benefit) cost are as follows: CWP Workers' Compensation For the Years Ended For the Years Ended December 31, December 31, 2011 2010 2009 2011 2010 2009Benefit obligations 4.46% 5.21% 5.84% 4.40% 5.13% 5.55%Net Periodic (benefit) costs 5.21% 5.84% 6.23% 5.13% 5.55% 5.90% Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers' Compensation costs. A one-quarterpercentage point change in assumed discount rate would have the following effect on benefit costs: 0.25 Percentage 0.25 Percentage Point Increase Point DecreaseCWP benefit increase (decrease) $634 $(606)Workers' Compensation costs (decrease) increase $(686) $721Cash Flows:CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2012. We intend to pay benefit claims as theybecome due.The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid: Workers' Compensation CWP Total Actuarial Other Benefits Benefits Benefits Benefits2012 $10,027 $31,375 $24,837 $6,5382013 $10,280 $31,360 $24,658 $6,7022014 $10,533 $31,576 $24,707 $6,8692015 $10,721 $31,925 $24,884 $7,0412016 $10,856 $32,328 $25,111 $7,217Year 2017-2021 $54,752 $169,785 $130,900 $38,885144NOTE 17—OTHER EMPLOYEE BENEFIT PLANS:UMWA 1974 Pension Trust:Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan (1974 Pension Trust EIN 52-1050282/002)negotiated with the United Mine Workers of America (UMWA) and contained in the National Bituminous Coal Wage Agreement (NBCWA). The 1974Pension Trust is overseen by a board of trustees, consisting of two union-appointed trustees and two employer-appointed trustees. The trustees' responsibilitiesinclude selection of the plan's investment policy, asset allocation, individual investment of plan assets and the administration of the plan. The benefitsprovided by the 1974 Pension Trust to the participating employees are determined based on age and years of service at retirement. The current 2011 NBCWAwill expire on December 31, 2016 and calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hoursworked by UMWA-represented employees. The required contribution called for by the current NBCWA for the period beginning January 1, 2012 and endingDecember 31, 2016 is $5.50 per hour worked. For the plan year ended June 30, 2011, approximately 18% of retirees and surviving spouses receiving benefitsfrom the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy.For the plan year ended June 30, 2011, approximately 28% of contributions made to the 1974 Pension Trust came from certain signatory subsidiaries ofCONSOL Energy. Total contributions made by signatory subsidiaries of CONSOL Energy to the UMWA 1974 Pension Trust were $36,209, $31,591 and$25,620, for the years ended December 31, 2011, 2010 and 2009, respectively. These multi-employer pension plan contributions are expensed as incurred.Total contributions for a year may differ from total expenses for the year due to the timing of actual contributions compared to the date of assessment.CONSOL Energy expects its signatory subsidiaries to contribute approximately $36,379 to the 1974 Pension Trust in 2012. Contributions to this multi-employer pension plan could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency ofother coal companies who currently contribute to the 1974 Pension Trust, lower than expected returns on pension assets or other funding deficiencies.Contribution rates for the 1974 Pension Trust required beyond December 31, 2016, cannot be estimated at this time.As of June 30, 2011, the most recent date for which information is available, the 1974 Pension Trust was underfunded. This determination wasmade in accordance with Employer Retirement Income Security Act of 1974 (ERISA) calculations, with a total actuarial asset value of $5,077,338 and a totalactuarial accrued liability of $6,618,702, or a funded percentage of approximately 76.5%. On October 21, 2011, certain subsidiaries of CONSOL Energyreceived notice from the trustees of the 1974 Pension Trust stating that the plan is considered to be “seriously endangered” for the plan year beginning July 1,2011. The Pension Protection Act (Pension Act) requires a funded percentage of 80% be maintained for this multi-employer pension plan, and if the plan isdetermined to have a funded percentage of less than 80% it will be deemed to be “endangered” or "seriously endangered", if the number of years to reach aprojected funding deficiency equals 7 or less in addition to having a funded percentage of less than 80%, and if less than 65%, it will be deemed to be in“critical” status. The funded percentage certified by the actuary for the 1974 Pension Trust was determined to be 76.50% under the Pension Act.Certain subsidiaries of CONSOL Energy face risks and uncertainties by participating in the 1974 Pension Trust. All assets contributed to the plan arepooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by signatory subsidiaries of CONSOL Energybenefit employees of other employers. If the 1974 Pension Trust fails to meet ERISA's minimum funding requirements or fails to develop and adopt arehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer's contribution to thismulti-employer pension plan. As a result of the 1974 Pension Trust's “seriously endangered” status, steps must be taken under the Pension Act to improve thefunded status of the plan. As a result, the Pension Protection Act requires the 1974 Pension Trust to adopt a funding improvement plan no later than May 25,2012, to improve the funded status of the plan, which may include increased contributions to the 1974 Pension Trust from employers in the future. Becausethe 2011 NBCWA established our signatory subsidiaries contribution obligations through December 31, 2016, our signatory subsidiaries' contributions tothe 1974 Pension Trust should not increase during the term of the NBCWA as a consequence of any funding improvement plan adopted by the 1974 PensionTrust to address the plan's seriously endangered status.Under current law governing multi-employer defined benefit plans, if certain signatory subsidiaries of CONSOL Energy voluntarily withdraw fromthe 1974 Pension Trust, the currently underfunded multi-employer defined benefit plan would require the withdrawing subsidiaries to make payments to theplan which would approximate the proportionate share of the multiemployer plan's unfunded vested benefit liabilities at the time of the withdrawal. The 1974Pension Trust uses a modified “rolling five” method for calculating an employer's share of the unfunded vested benefits, or the withdrawal liability, for a planyear. An employer would be obligated to pay its pro-rata share of the unfunded vested benefits based on the ratio of hours worked by the employer's employeesduring the previous five plan years for which contributions were due compared to the number of hours worked by all the employees of the employers fromwhich contributions were due. The 1974 Pension Trust's unfunded vested benefits at June 30, 2011, the end of the latest plan year, were $4,288,252.CONSOL Energy's signatory subsidiaries' percentage of hours worked145compared during the previous five plan years to the total hours worked by all plan participants during the same period was estimated to be approximately28%. These factors result in an estimated withdrawal liability of approximately $1,196,946.UMWA Benefit Trusts:The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of AmericaCombined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. CONSOL Energysubsidiaries account for required contributions to these multi-employer trusts as expense when incurred. The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefitsas of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement onFebruary 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to formeremployers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires thatresponsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognizedwhen contributions are assessed. Total contributions under the Act were $13,609, $19,904, and $22,646 for the years ended December 31, 2011, 2010 and2009, respectively. Based on available information at December 31, 2011, CONSOL Energy's obligation for the Act is estimated at approximately $183,651.The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the NBCWA of 1993. This planprovides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose lastemployer signed the 1993 or a later NBCWA and who subsequently goes out of business. Contributions to the trust under the 2011 labor agreement are $0.50per hour worked by UMWA represented employees for the year ended December 31, 2011. Contributions to the trust under the 2007 agreement were $1.42 perhour worked by UMWA represented employees for the year ended December 31, 2010, comprised of a $0.50 per hour worked under the labor agreement and$0.92 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust underthe 2007 agreement were $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hourworked under the labor agreement and $0.94 per hour worked by UMWA represented employees under the 2006 Act. Total contributions were $3,824,$9,086 and $8,968 for the years ended December 31, 2011, 2010 and 2009, respectively.Pursuant to the provisions of the 2006 Act and the 1992 Plan, CONSOL Energy is required to provide security in an amount based on the annual costof providing health care benefits for all individuals receiving benefits from the 1992 Plan who are attributable to CONSOL Energy, plus all individualsreceiving benefits from an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the 2006Act and the 1992 Plan, the outstanding letters of credit to secure our obligation were $67,349, $67,768, and $61,734 for years ended December 31, 2011,2010 and 2009, respectively. The 2011, 2010 and 2009 security amounts were based on the annual cost of providing health care benefits and included areduction in the number of eligible employees.At December 31, 2011, approximately 32% of CONSOL Energy's workforce was represented by the UMWA.Equity Incentive Plans:CONSOL Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 18–Stock Based Compensation for further discussion of CONSOL Energy's equity incentive plans.On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas outstanding common stock pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. As a result of this acquisition, CNX Gas no longer has its own independent equityincentive plan. Prior to the acquisition, the CNX Gas equity incentive plan consisted of the following components: stock options, stock appreciation rights,restricted stock units, performance awards, performance share units, cash awards and other stock-based awards. The total number of shares of CNX Gascommon stock with respect to which awards could be granted under CNX Gas' plan was 2,500,000. CNX Gas stock-based compensation expense resulted inpre-tax expense of $2,766, $2,043 and $6,311 for the years ended December 31, 2011, 2010 and 2009, respectively.Long Term Incentive Compensation:Prior to the acquisition of the minority interest in CNX Gas, CNX Gas had a long-term incentive program. This program allowed for the award ofperformance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of theCompany's common stock at the program vesting date. The total number of units earned, if any, by a participant was based on the Company's total stockholder return relative to the stock holder return of a pre-146determined peer group of companies. CNX Gas recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. A credit to expense of approximately $1,434 was recognized during the year ended December 31, 2009 as a result of the decline in the value ofthe expected payout prior to the exchange transaction discussed below.During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term IncentiveProgram to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restrictedstock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized.As a result of the completed exchange offer there are no outstanding performance share units.Investment Plan:CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company contributionwas 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose contribution remains a match of 50%of the first 12% of base pay contributed by the employee. Total payments and costs were $30,532, $27,221, and $24,353 for the years ended December 31,2011, 2010 and 2009, respectively.Long-Term Disability:CONSOL Energy has a Long-Term Disability Plan available to all eligible full-time salaried employees. The benefits for this plan are based on apercentage of monthly earnings, offset by all other income benefits available to the disabled. For the Years Ended December 31, 2011 2010 2009Benefit Costs $6,439 $3,294 $3,642Discount rate assumption used to determine net periodic benefit costs 4.04% 4.72% 5.92%Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities–Other and Other Accrued Liabilities and amounted to$35,638 and $36,233 at December 31, 2011 and 2010, respectively.NOTE 18—STOCK-BASED COMPENSATION:CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards tokey employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In2009, the Board of Directors approved an increase in the total number of shares by 5,600,000 bringing the total number of shares of common stock that canbe covered by grants to 23,800,000. At December 31, 2011, 3,137,524 shares are available for all awards. The Plan, as amended, provides that the aggregatenumber of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of stock options and by 1.44 for eachshare issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the planafter the tenth anniversary of the effective date of the award.CONSOL Energy recognizes stock-based compensation costs for only those shares expected to vest on a straight-line basis over the requisite serviceperiod of the award, which is generally the option vesting term, or to an employee's eligible retirement date, if earlier and applicable. The total stock-basedcompensation expense recognized was $46,076, $45,550 and $32,723 for the years ended December 31, 2011, 2010 and 2009, respectively. The relateddeferred tax benefit totaled $17,325, $17,473 and $12,490, for the years ended December 31, 2011, 2010 and 2009, respectively.CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based oncertain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations. CONSOL Energy uses the Black-Scholesoption pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the twoemployee populations. The expected term computation is based upon historical exercise patterns and post-vesting termination behavior of the populations. Therisk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected termof the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determineexpected volatility and future stock price trends. Total fair value of options granted during the years ended December 31, 2011, 2010 and 2009 were $9,913,$10,361 and $9,950, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with thefollowing assumptions and weighted average fair values:147 December 31, 2011 2010 2009Weighted average fair value of grants $20.47 $21.97 $14.48Risk-free interest rate 1.61% 1.88% 1.45%Expected dividend yield 0.82% 0.80% 1.40%Expected forfeiture rate 2.00% 2.00% 2.00%Expected volatility 55.10% 59.00% 75.60%Expected term in years 4.26 4.04 4.10A summary of the status of stock options granted is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands)Balance at December 31, 2010 5,453,241 $29.59 Granted 484,263 $48.59 Exercised (579,767) $15.59 Forfeited (22,227) $36.32 Balance at December 31, 2011 5,335,510 $32.79 4.67 $51,962Vested and expected to vest 5,325,845 $32.76 4.85 $51,961Exercisable at December 31, 2011 4,339,329 $29.75 4.00 $49,382These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Planadopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded afterDecember 31, 2006 vest 33% per year, beginning one year after the grant date. There are 4,965,695 stock options outstanding under the Equity Incentiveplan. Additionally, there are 291,612 fully vested employee stock options outstanding which vested under terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 78,203 stock options outstanding under these grants. Thevesting of all options will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy. In 2008,the compensation committee of the board of directors changed the retirement eligible acceleration of vesting to require a minimum vesting period of twelvemonths. This change is effective for all stock based compensation awards issued after January 1, 2008.The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy's closing stock priceon the last trading day of the year ended December 31, 2011, and the option's exercise price, multiplied by the number of in-the-money options) that wouldhave been received by the option holders had all option holders exercised their options on December 31, 2011. This amount varies based on the fair marketvalue of CONSOL Energy's stock. Total intrinsic value of options exercised for the year ended December 31, 2011, 2010 and 2009 was $18,049, $10,722and $4,502, respectively.Cash received from option exercises for the years ended December 31, 2011, 2010 and 2009 was $9,033, $5,993 and $2,547, respectively. The excesstax benefit realized for the tax deduction from option exercises totaled $8,281, $15,365, and $3,270, for the years ended December 31, 2011, 2010 and2009, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.148Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awardsentitle the holder to receive shares of common stock as the award vests. Compensation expense is recognized over the vesting period of the units. The total fairvalue of the restricted stock units granted during the years ended December 31, 2011, 2010 and 2009 was $24,882, $28,762 and $42,720, respectively. Thetotal fair value of shares vested during the years ended December 31, 2011, 2010 and 2009 was $16,496, $22,244 and $18,092, respectively. The followingrepresents the unvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant: Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2010 1,168,444 $38.63Granted 515,804 $48.24Vested (435,825) $37.85Forfeited (28,070) $44.70Nonvested at December 31, 2011 1,220,353 $42.83Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance share unit awards. These awards entitle the holder to receiveshares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performancemeasurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification forawards with market and performance vesting conditions. At December 31, 2011, achievement of the market and performance goals is believed to be probable.The total fair value of performance share units granted during the years ended December 31, 2011, 2010 and 2009 was $11,648, $8,882 and $5,684. Thefollowing represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant: Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2010 338,013 $53.36Granted 211,743 $55.01Vested (40,752) $86.41Nonvested at December 31, 2011 509,004 $51.40Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance stock options. These awards entitle the holder to receiveshares of common stock subject to the achievement of certain performance goals. Compensation expense is recognized over the vesting period of the units. AtDecember 31, 2011, achievement of the performance goals is believed to be probable. The total fair value of performance share options vested during the yearended December 31, 2011 was $3,299. The following represents the unvested performance options and their corresponding fair value (based upon the closingshare price) at the date of grant: Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2010 802,804 $16.44Vested (200,697) $16.44Nonvested at December 31, 2011 602,107 $16.44As of December 31, 2011, $36,643 of total unrecognized compensation cost related to all unvested stock-based awards is expected to be recognized overa weighted-average period of 1.66 years. When stock options are exercised and restricted and performance stock unit awards become vested, the issuances aremade from CONSOL Energy's treasury stock shares which have been acquired as part of CONSOL Energy's share repurchase program as previouslydiscussed in Note 1–Significant Accounting Policies.149NOTE 19—ACCUMULATED OTHER COMPREHENSIVE LOSS:Components of accumulated other comprehensive loss consist of the following: TreasuryRateLock Change inFair Valueof Cash FlowHedges Adjustmentsfor ActuariallyDeterminedLiabilities Adjustments forNon-controllingInterest AccumulatedOtherComprehensiveLossBalance at December 31, 2008$263 $124,510 $(564,744) $(21,929) $(461,900)Net increase in value of cash flow hedge$— $186,824 $— $(31,162) $154,700Reclassification of cash flow hedges from othercomprehensive income to earnings$— $(239,956) $— $40,024 $(198,970)Current period change$(83) $— $(134,549) $298 $(134,334)Balance at December 31, 2009$180 $71,378 $(699,293) $(12,769) $(640,504)Net increase in value of cash flow hedge$— $140,985 $— $(12,500) $128,540Reclassification of cash flow hedges from othercomprehensive income to earnings$— $(166,276) $— $7,248 $(159,083)Elimination of noncontrolling interest from purchase ofCNX Gas$— $— $— $18,026 $18,026Current period change$(84) $— $(221,228) $(5) $(221,317)Balance at December 31, 2010$96 $46,087 $(920,521) $— $(874,338)Net increase in value of cash flow hedge$— $200,699 $— $— $200,699Reclassification of cash flow hedges from othercomprehensive income to earnings$— $(95,006) $— $— $(95,006)Current period change$(96) $— $(32,813) $— $(32,909)Balance at December 31, 2011$— $151,780 $(953,334) $— $(801,554)The cash flow hedges that CONSOL Energy holds are disclosed in Note 23–Derivative Instruments. The adjustments for Actuarially DeterminedLiabilities are disclosed in Note 15–Pension and Other Postretirement Benefit Plans and Note–16 Coal Workers' Pneumoconiosis (CWP) and Workers'Compensation.NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION:The following are non-cash transactions that impact the investing and financing activities of CONSOL Energy. For non-cash transactions that relate toacquisitions and dispositions, refer to Note 2.CONSOL Energy holds capital leases on automobiles for company use. The amortization of the capital asset results in a non-cash transaction as theasset has not yet been purchased. The capital lease obligations result in non-cash transactions of $7,389, $7,158, and $3,375 for the years ended December31, 2011, 2010, and 2009, respectively.In 2009, CONSOL Energy sold an aircraft hangar in exchange for a note receivable of $989. Also during 2009, CONSOL Energy completed a landsale to Noble Co. - B&N Coal, Inc. in exchange for a note receivable in the amount of $800.The following table shows cash paid during the year for: For the Years Ended December 31, 2011 2010 2009Interest (Net of Amounts Capitalized) $258,134 $152,155 $26,425Income Taxes $144,405 $118,550 $131,043150NOTE 21—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:CONSOL Energy markets thermal coal, principally to electric utilities in the United States, Canada and Western Europe, metallurgical coal to steel andcoke producers worldwide, and natural gas primarily to gas wholesalers.Concentration of credit risk is summarized below: December 31, 2011 2010Thermal coal utilities $210,164 $220,052Steel and coke producers 93,303 69,470Coal brokers and distributors 38,033 54,996Gas wholesalers 63,299 65,358Various other 58,013 42,654Total Accounts Receivable Trade (including Accounts Receivable—Securitized) $462,812 $452,530Accounts receivable from thermal coal utilities and steel and coke producers include amounts sold under the accounts receivable securitization facility.See Note 9–Accounts Receivable Securitization for further discussion. Credit is extended based on an evaluation of the customer's financial condition, andgenerally collateral is not required. Credit losses have been consistently minimal.For the year ended December 31, 2011 sales to our largest coal customer, Xcoal Energy Resources, comprised over 10% of our revenues. Coal sales toXcoal Energy Resources were $662,109 during 2011. For the years ended December 31, 2010 and 2009, no customer comprised over 10% of our revenues.NOTE 22—FAIR VALUE OF FINANCIAL INSTRUMENTS:The financial instruments measured at fair value on a recurring basis are summarized below: Fair Value Measurements at December 31, 2011 Fair Value Measurements at December 31, 2010DescriptionQuoted Prices inActive Marketsfor IdenticalLiabilities(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3) Quoted Prices inActive Marketsfor IdenticalLiabilities(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3)Gas Cash Flow Hedges (Note 23)$— $251,277 $— $— $76,240 $—The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to theshort-term maturity of these instruments.Restricted cash: The carrying amount reported in the balance sheets for restricted cash approximates its fair value due to the short-term maturity ofthese instruments.Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.Borrowings under Securitization Facility: The carrying amount reported in the balance sheets for borrowings under the securitization facilityapproximates its fair value due to the short-term maturity of these instruments.Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses.The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.151The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows: December 31, 2011 December 31, 2010 CarryingAmount FairValue CarryingAmount FairValueCash and cash equivalents$375,736 $375,736 $32,794 $32,794Restricted cash$22,148 $22,148 $20,291 $20,291Short-term notes payable$— $— $(284,000) $(284,000)Borrowings under securitization facility$— $— $(200,000) $(200,000)Long-term debt$(3,133,993) $(3,422,452) $(3,145,365) $(3,341,406)NOTE 23—DERIVATIVE INSTRUMENTS:CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. We measure each derivativeinstrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently inearnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivativeinstrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of thederivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecastedtransaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period. CONSOL Energy currently utilizes only cashflow hedges that are considered highly effective.CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis whether each derivative is highly effective in offsettingchanges in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases tobe a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject tocontinuing review. The Company has not experienced any issues of non-performance by derivative counterparties.CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. Theobjective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodity. As of December31, 2011, the total notional amount of the Company’s outstanding natural gas swap contracts was 164.1 billion cubic feet. These swap contracts areforecasted to settle through December 31, 2015 and meet the criteria for cash flow hedge accounting. During the next twelve months, $93,298 of unrealizedgain is expected to be reclassified from Other Comprehensive Income and into earnings, as a result of the settlement of cash flow hedges. No gains or losseshave been reclassified into earnings as a result of the discontinuance of cash flow hedges.The fair value at December 31, 2011 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flow hedges, wasan asset of $251,277. The total asset is comprised of $153,376 and $97,901 which were included in Prepaid Expense and Other Assets, respectively, on theConsolidated Balance Sheets.The fair value at December 31, 2010 of CONSOL Energy’s derivative instruments, which were all natural gas swaps and qualify as cash flowhedges, was an asset of $79,960 and a liability of $3,720. The total asset is comprised of $52,022 and $27,938 which were included in Prepaid Expenseand Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $3,191 and $529 which were included in OtherAccrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.152The effect of derivative instruments in cash flow hedging relationships on the Consolidated Statements of Income and the Consolidated Statements ofStockholders' Equity are as follows: Year Ended December 31, 201120102009Natural Gas Price Swaps Gain recognized in Accumulated OCI$200,699$140,985$186,824Gain reclassified from Accumulated OCI into Outside Sales$95,006$166,276$239,956Gain/(Loss) recognized in Outside Sales for ineffectiveness $1,034$31$(962)NOTE 24—COMMITMENTS AND CONTINGENGENT LIABILITIES:CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death,damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes andother claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable andcan be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position,results of operations or cash flows of CONSOL Energy. It is possible that the aggregate loss in the future with respect to these lawsuits and claims couldultimately be material to the financial position, results of operations or cash flows of CONSOL Energy; however, such amount cannot be reasonablyestimated. The amount claimed against CONSOL Energy is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often thecase. The maximum aggregate amount claimed in those lawsuits and claims, regardless of probability, where a claim is expressly stated or can be estimatedexceeds the aggregate amounts accrued for all lawsuits and claims by approximately $1,387,000.The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized.American Electric Corp: On August 8, 2011, the United States Environmental Protection Agency, Region IV, sent Consolidation Coal Company a GeneralNotice and Offer to Negotiate regarding the Ellis Road/American Electric Corp. Superfund Site in Jacksonville, Florida. The General Notice was sent toapproximately 180 former customers of American Electric Corp. CONSOL Energy has confirmed that it did business with American Electric Corp. in1983‑84. The General Notice indicates that the Environmental Protection Agency (EPA) has determined that polychlorinated biphenyls (PCBs) and othercontaminants in the soils and sediments at and near the site require a removal action to address those areas. The Offer to Negotiate invites the potentiallyresponsible parties (PRPs) to enter into an Administrative Settlement Agreement and Order on Consent to provide for conducting the removal action under theEPA oversight and to reimburse the EPA for its past costs, in the amount of $384 and for its future costs. CONSOL Energy has responded to the EPAindicating its willingness to participate in such negotiations, and CONSOL Energy is participating in the formation of a group of potentially responsibleparties to consider conducting the removal action. The actual scope of the work has yet to be determined, but the current estimate of the total costs of theremoval action is in the range of $2,000 to $5,000, with CONSOL Energy's share of such costs at approximately 8%. CONSOL Energy has established aninitial accrual based on its percentage share of the costs at the high end of the range. The liability is immaterial to the overall financial position of CONSOLEnergy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet.Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is apotentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and LiabilityAct of 1980, as amended (CERCLA), with respect to the Ward Transformer site in Wake County, North Carolina. The EPA, CONSOL Energy and twoother PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removalaction, at and in the vicinity of the Ward Transformer property. In June 2008, while conducting the PCB soil excavation on the Ward property, it wasdetermined that PCBs have migrated onto adjacent properties. The current estimated cost of remedial action for the area CONSOL Energy was originallynamed a PRP, including payment of the EPA's past and future cost, is approximately $65,000. The current estimated cost of the most likely remediation planfor the additional areas discovered is approximately $11,000. Also, in September 2008, the EPA notified CONSOL Energy and sixty other PRPs that therewere additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for thisarea are not yet available. CONSOL Energy recognized $3,502 and $3,422 of expense in Cost of Goods Sold and Other charges in the years ended December31, 2010 and 2009, respectively. The amounts recognized in Cost of Goods Sold and Other Charges for the year ended December 31, 2011 were immaterial.CONSOL Energy also153funded $250, $1,209 and $5,500 in the years ended December 31, 2011, 2010 and 2009, respectively, to an independent trust established for thisremediation. As of December 31, 2011, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claimsagainst approximately 225 nonparticipating PRPs to recover a share of the costs incurred and to be incurred to conduct the removal actions at the Ward Site.CONSOL Energy's portion of recoveries from settled claims is $4,491. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by thesesettled claims. The remaining net liability at December 31, 2011 is $3,468.Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as adefendant in approximately 7,500 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Texas and Illinois.Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many ofthe pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont todetermine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont.In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability ofsuch indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have soughtprotection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on over 15 years ofexperience with this litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financialposition of CONSOL Energy and is included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect toasbestos cases have not been material.The following lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly no accrual has beenrecognized.Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the Commonwealth) filed a six-count Complaint inthe Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company's underground longwall mining activities at its Bailey Minecaused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently altered the dam, thereby eliminating the Ryerson Park Lake.The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resource damages totaling $58,000.On February 16, 2010, the Department of Environmental Protection (DEP) issued its interim report, concluding that the alleged damage was subsidencerelated. The DEP estimated the cost of repair to be approximately $20,000. The Company has appealed the DEP's findings to the Pennsylvania EnvironmentalHearing Board (PEHB), which will consider the case de novo, meaning without regard to the DEP's decision, as to any finding of causation of damage and/orthe amount of damages. Either party may appeal the decision of the PEHB to the Pennsylvania Commonwealth Court, and then, as may be allowed, to thePennsylvania Supreme Court. A hearing on the merits of the case will not occur until sometime in the spring or summer of 2013. As to the underlying claim,CONSOL Energy believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims.For that reason, we have not accrued a liability for this claim; however, if CONSOL Energy is ultimately found to be liable for damages to the dam, webelieve the range of loss would be between $9,000 and $30,000.South Carolina Gas & Electric Company Arbitration: South Carolina Electric & Gas Company (SCE&G), a utility, has demanded arbitration, seeking$36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company, both wholly owned subsidiaries of CONSOL Energy. SCE&Gclaims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. CONSOL Energycounterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for April 30, 2012. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the actionfiled against them. For that reason, we have not accrued a liability for this claim. If the named CONSOL Energy defendants prevail, the range of recoverywould be between $5,100 and $6,800. If liability is ultimately imposed on the named CONSOL Energy defendants, we believe the range of loss would bebetween $16,000 and $27,000.CNX Gas Shareholders Litigation: CONSOL Energy has been named as a defendant in five putative class actions brought by alleged shareholders of CNXGas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for$38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the three cases filed in the Delaware Chancery Court havebeen consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL). All five actions generally allege that CONSOL Energybreached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 pershare price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, theactions sought a permanent injunction against or rescission of the tender offer, damages, and attorneys' fees and expenses. The lawsuit will likely go to trial,possibly in 2012. CONSOL154Energy believes that these actions are without merit and intends to defend them vigorously. For that reason, we have not accrued a liability for this claim;however, if liability is ultimately imposed, based on the expert reports that have been exchanged by the parties, we believe the range of loss could be up to$221,000.The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly, noaccrual has been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include, butare not limited to, generalized allegations of unspecified damages (such as improper deductions), discovery having not commenced or not having beencompleted, unavailability of expert reports on damages and non-monetary issues are being tried. For example, in instances where a gas lease termination issought, damages would depend on speculation as to if and when the gas production would otherwise have occurred, how many wells would have been drilledon the lease premises, what their production would be, what the cost of production would be, and what the price of gas would be during the production period.An estimate is calculated, if applicable, when sufficient information becomes available.C. L. Ritter: On March 1, 2011, the Company was served with a complaint instituted by C. L. Ritter Lumber Company Incorporated against ConsolidationCoal Company (CCC), Island Creek Coal Company, (ICCC), CNX Gas Company LLC, subsidiaries of CONSOL Energy Inc., as well as CONSOLEnergy itself in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water frommining activities at CCC's Buchanan Mine into nearby void spaces at one of the mines of ICCC. The suit alleges damages of between $34,000 and $430,000for alleged damage to coal and coalbed methane, as well as breach of contract damages. We have removed the case to federal court and filed a motion todismiss, largely predicated on the statute of limitations bar. The trial judge ruled that the issue of the applicability of the statute of limitations bar can only beaddressed after discovery. Three similar lawsuits were filed recently, one in the same court and two in the Circuit Court of Buchanan County, Virginia, byother plaintiffs that collectively allege damages of between $100,000 and $622,000. The Company has or intends to file motions to dismiss those suits as well.One of the three suits which claimed damages of $22,000 has been dismissed in federal court and has been appealed. CCC believes that it had, and continuesto have, the right to store water in these void areas. CCC and the other named CONSOL Energy defendants deny all liability and intend to vigorously defendthe action filed against them in connection with the removal and deposit of water from the Buchanan Mine. Consequently, we have not recognized any liabilityrelated to these actions.Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, Virginia styled Hale v. CNX GasCompany LLC et. al. The lawsuit alleges that the plaintiff class consists of oil and gas owners, that the Virginia Supreme Court has decided that coalbedmethane (CBM) belongs to the owner of the oil and gas estate, that the Virginia Gas and Oil Act of 1990 unconstitutionally allows force pooling of CBM, thatthe Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the force pooling orders, and that the Company only relied uponcontrol of the coal estate in force pooling the CBM notwithstanding the Virginia Supreme Court decision holding that if only the coal estate is controlled, theCBM is not thereby controlled. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is,the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The Magistrate Judge issued a Report andRecommendation in which she recommended that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8royalty, and that CNX Gas need not distribute the net proceeds to class members. The Magistrate Judge recommended against the dismissal of certain otherclaims, none of which are believed to have any significance The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. Theplaintiffs and CNX Gas have agreed to stay this litigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.Consequently, we have not recognized any liability related to these actions.Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in Federal court in Virginia styled Addison v. CNX Gas Company LLC. Thecase involves two primary claims: (i) the plaintiff and similarly situated CNX Gas lessors identified as conflicting claimants during the force pooling processbefore the Virginia Gas and Oil Board are the owners of the CBM and, accordingly, the owners of the escrowed royalty payments being held by theCommonwealth of Virginia; and (ii) CNX Gas Company failed to either pay royalties due these conflicting claimant lessors or paid them less than requiredbecause of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiffs seek a declaratoryjudgment regarding ownership and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking), for forcepooling coal owners after the Ratliff decision declared coal owners did not own the CBM; negligent breach of duties as an operator; breach of fiduciary duties;and unjust enrichment. We filed a Motion to Dismiss in this case, and the Magistrate Judge recommended dismissing some claims and allowing others toproceed. The District Judge affirmed the Magistrate Judge's Recommendations in their entirety. The plaintiffs and CNX Gas Company have agreed to stay thislitigation. CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liabilityrelated to these actions.155Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County PennsylvaniaCommon Pleas Court. The named plaintiff is Earl D. Hall. The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Explorationand Production Company, whose leases were acquired by CONSOL Energy. The complaint alleges more than 1,000 similarly situated lessors. The lawsuitalleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis,(ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs thatwere not arms-length, (iv) not paying royalties on gas lost or used before the point of sale, and (v) not paying royalties on oil production. The complaint alsoalleges that royalty statements were false and misleading. The complaint seeks damages, interest and an accounting on a well-by-well basis. CONSOL Energybelieves that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to these actions.Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company and CONSOLEnergy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energy trespassed andconverted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas Company. The complaint, as amended,seeks injunctive relief, including removing CNX Gas Company from the property, and compensatory damages of $20,000. The suit also sought to overturnexisting law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal thatdismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff's summaryjudgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and briefing will take place before a decision isrendered. CNX Gas Company and CONSOL Energy believe this lawsuit to be without merit and intend to vigorously defend it. Consequently, we have notrecognized any liability related to these actions.Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion Resources, andEQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease in southern WestVirginia. EQT was the original lessee, but they farmed out the development of the lease to Dominion, in exchange for an overriding royalty. Dominion sold theindirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, the subsidiary that held the leasewas merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion's sale of the subsidiary to CONSOL Energy wasa change in control that required its consent under the terms of the farmout agreement and lease, and (ii) the subsequent merger of the subsidiary into CNXGas Company was an assignment that required its consent under the lease. Rowland alleges that the failure to obtain the required consent constitutes a breachof the lease and it seeks damages and a forfeiture of the lease. CONSOL Energy and CNX Gas Company have filed a motion to dismiss the complaint,arguing among other things, that Dominion's sale of the indirect subsidiary was not a change in control; that even if the sale constituted a change in control,the purchase agreement between Dominion and CONSOL Energy did not give effect to the transfer so the transfer never occurred; that the mergers did notrequire consent; and that Rowland did not provide timely notice of breach of the lease in accordance with its terms. Rowland is amending its complaint toinclude allegations that CONSOL Energy and Dominion Resources are liable for their subsidiaries' actions. We will file a motion to dismiss in response.CONSOL Energy believes that the case is without merit and intends to defend it vigorously. Consequently, we have not recognized any liability related to theseactions.Majorsville Storage Field Declaratory Judgment: On March 3, 2011, an attorney sent a letter to CNX Gas Company regarding certain leases that CNX GasCompany obtained from Columbia Gas in Greene County, Pennsylvania involving the Majorsville Storage Field. The letter was written on behalf of threelessors alleging that the leases totaling 525 acres are invalid, and had expired by their terms. The plaintiffs' theory is that the rights of storage and productionare severable under the leases. Ignoring the fact that the leases have been used for gas storage, they claim that since there has been no production or developmentof production, the right to produce gas expired at the end of the primary terms. On June 16, 2011 in the Court of Common Pleas of Greene County,Pennsylvania, the Company filed a declaratory judgment action, seeking to have a court confirm the validity of the leases. We believe that we will prevail inthis litigation based on the language of the leases and the current status of the law. Consequently, we have not recognized any liability related to these actions.156The following lawsuit and claims include those for which a loss is remote and accordingly, no accrual has been recognized, although if a non favorableverdict were received the impact could be material.Comer Litigation: In 2005, plaintiffs Ned Comer and others filed a purported class action lawsuit in the U.S. District Court for the Southern District ofMississippi against a number of companies in energy, fossil fuels and chemical industries, including CONSOL Energy styled, Comer, et al. v. Murphy Oil,et al. The plaintiffs, residents and owners of property along the Mississippi Gulf coast, alleged that the defendants caused the emission of greenhouse gasesthat contributed to global warming, which in turn caused a rise in sea levels and added to the ferocity of Hurricane Katrina, which combined to destroy theplaintiffs' property. The District Court dismissed the case and the plaintiffs appealed. The Circuit Court panel reversed and the defendants sought a rehearingbefore the entire court. A rehearing before the entire court was granted, which had the effect of vacating the panel's reversal, but before the case could be heardon the merits, a number of judges recused themselves and there was no longer a quorum. As a result, the District Court's dismissal was effectively reinstated.The plaintiffs asked the U.S. Supreme Court to require the Circuit Court to address the merits of their appeal. On January 11, 2011, the Supreme Courtdenied that request. Although that should have resulted in the dismissal being a finality, the plaintiffs filed a lawsuit on May 27, 2011, in the samejurisdiction against essentially the same defendants making nearly identical allegations as in the original lawsuit. The defendants intend to seek an earlydismissal of the case.At December 31, 2011, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit tocertain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that wecould be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions.Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to thesefinancial guarantees and letters of credit are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees willexpire without being funded, and therefore the commitments will not have a material adverse effect on financial condition. Amount of CommitmentExpiration Per Period TotalAmountsCommitted Less Than1 Year 1-3 Years 3-5 Years Beyond5 YearsLetters of Credit: Employee-Related$198,447 $128,645 $69,802 $— $—Environmental56,994 23,076 33,918 — —Other80,508 43,561 36,947 — —Total Letters of Credit335,949 195,282 140,667 — —Surety Bonds: Employee-Related204,895 204,895 — — —Environmental442,698 439,435 3,263 — —Other27,776 27,763 12 — 1Total Surety Bonds675,369 672,093 3,275 — 1Guarantees: Coal79,800 30,752 26,548 18,500 4,000Gas100,223 54,613 14,988 — 30,622Other451,640 80,237 139,642 86,721 145,040Total Guarantees631,663 165,602 181,178 105,221 179,662Total Commitments$1,642,981 $1,032,977 $325,120 $105,221 $179,663Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and variousstate workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performancebonds related to reclamation and other environmental issues. Coal and Gas financial guarantees have primarily been provided to support various salescontracts. Other guarantees have been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and variousother items necessary in the normal course of business.157CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firmtransportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheet. Asof December 31, 2011, the purchase obligations for each of the next five years and beyond were as follows: Obligations DueAmountLess than 1 year$242,9821 - 3 years396,5163 - 5 years471,047More than 5 years1,649,325Total Purchase Obligations$2,759,870Costs related to these purchase obligations include: For The Years Ended December 31, 2011 2010 2009Gas drilling obligations$108,167 $28,641 $—Firm transportation expense59,606 40,274 21,668Major equipment purchases43,698 56,723 89,261Other891 497 120Total costs related to purchase obligations$212,362 $126,135 $111,049NOTE 25—SEGMENT INFORMATION:CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal division are mining, preparation andmarketing of thermal coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes fourreportable segments. These reportable segments are Thermal, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportablesegments includes a number of operating segments (mines or type of coal sold). For the year ended December 31, 2011, the Thermal aggregated segmentincludes the following mines: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run andShoemaker. For the year ended December 31, 2011, the Low Volatile Metallurgical aggregated segment includes the Buchanan Mine. For the year endedDecember 31, 2011, the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex, Loveridge, Miller CreekComplex and Robinson Run coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activitiesassigned to the Coal division but not allocated to each individual mine. The principal activity of the Gas division is to produce pipeline quality natural gas forsale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, ShallowOil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the Gas division butnot allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supplyservices and other business activities. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based onsales less identifiable operating and non-operating expenses.158Industry segment results for the year ended December 31, 2011 are: Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal CoalbedMethane MarcellusShale Shallow Oil andGas OtherGas TotalGas AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$3,058,193 $1,071,570 $368,221 $68,864 $4,566,848 $462,677 $118,973 $155,444 $11,370 $748,464 $345,501 $— $5,660,813(A)Sales—purchased gas— — — — — — — — 4,344 4,344 — — 4,344 Sales—gas royaltyinterests— — — — — — — — 66,929 66,929 — — 66,929 Freight—outside— — — 231,536 231,536 — — — — — — — 231,536 Intersegment transfers— — — — — — — — 3,303 3,303 194,857 (198,160) — Total Sales and Freight$3,058,193 $1,071,570 $368,221 $300,400 $4,798,384 $462,677 $118,973 $155,444 $85,946 $823,040 $540,358 $(198,160) $5,963,622 Earnings (Loss) BeforeIncome Taxes$456,306 $680,495 $135,343 $(338,995) $933,149 $154,486 $35,641 $(23,151) $(37,192) $129,784 $17,983 $(292,963) $787,953(B)Segment assets $5,253,226 $6,183,582 $351,370 $737,522 $12,525,700(C)Depreciation, depletionand amortization $392,765 $206,821 $18,811 $— $618,397 Capital expenditures $676,587 $664,612 $41,172 $— $1,382,371 (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.159Industry segment results for the year ended December 31, 2010 are: Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal CoalbedMethane MarcellusShale Shallow Oil andGas OtherGas TotalGas AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$3,001,352 $680,212 $172,087 $45,738 $3,899,389 $569,367 $48,769 $116,679 $7,741 $742,556 $296,758 $— $4,938,703(D)Sales—purchased gas— — — — — — — — 11,227 11,227 — — 11,227 Sales—gas royaltyinterests— — — — — — — — 62,869 62,869 — — 62,869 Freight—outside— — — 125,715 125,715 — — — — — — — 125,715 Intersegment transfers— — — — — — — — 3,253 3,253 175,906 (179,159) — Total Sales and Freight$3,001,352 $680,212 $172,087 $171,453 $4,025,104 $569,367 $48,769 $116,679 $85,090 $819,905 $472,664 $(179,159) $5,138,514 Earnings (Loss) BeforeIncome Taxes$460,697 $381,562 $86,918 $(392,683) $536,494 $248,127 $5,910 $(4,179) $(69,980) $179,878 $22,156 $(270,615) $467,913(E)Segment assets $5,056,583 $5,916,093 $337,855 $760,079 $12,070,610(F)Depreciation, depletionand amortization $359,497 $190,424 $17,742 $— $567,663 Capital expenditures $707,473 $3,891,640 $25,123 $— $4,624,236(G)(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.160Industry segment results for the year ended December 31, 2009 are: Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal CoalbedMethane MarcellusShale Shallow Oiland Gas OtherGas TotalGas AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$3,122,223 $248,546 $— $39,117 $3,409,886 $595,769 $21,006 $7,907 $4,247 $628,929 $272,976 $— $4,311,791(H)Sales—purchasedgas— — — — — — — — 7,040 7,040 — — 7,040 Sales—gasroyaltyinterests— — — — — — — — 40,951 40,951 — — 40,951 Freight—outside— — — 148,907 148,907 — — — — — — — 148,907 Intersegmenttransfers— — — — — — — — 1,671 1,671 152,375 (154,046) — TotalSales andFreight$3,122,223 $248,546 $— $188,024 $3,558,793 $595,769 $21,006 $7,907 $53,909 $678,591 $425,351 $(154,046) $4,508,689 Earnings (Loss)BeforeIncomeTaxes$718,947 $93,688 $— $(265,906) $546,729 $303,882 $3,940 $(2,259) $(42,115) $263,448 $15,686 $(37,518) $788,345(I)Segment assets $4,722,508 $2,171,495 $317,004 $564,394 $7,775,401(J)Depreciation,depletionandamortization $310,346 $107,251 $19,820 $— $437,417 Capitalexpenditures $580,401 $322,126 $17,553 $— $920,080 (H) There were no sales to customers aggregating over 10% of total revenue in 2009.(I) Includes equity in earnings of unconsolidated affiliates of $5,663, $636 and $9,408 for Coal, Gas and All Other, respectively.(J) Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.161Reconciliation of Segment Information to Consolidated Amounts:Revenue and Other Income: For the Years Ended December 31, 2011 2010 2009Total segment sales and freight from external customers $5,963,622 $5,138,514 $4,508,689Other income not allocated to segments (Note 3) 153,620 97,507 113,186Total Consolidated Revenue and Other Income $6,117,242 $5,236,021 $4,621,875Earnings Before Income Taxes: For the Years Ended December 31, 2011 2010 2009Segment Earnings Before Income Taxes for total reportable business segments $1,062,933 $716,372 $810,177Segment Earnings Before Income Taxes for all other businesses 17,983 22,156 15,686Interest income (expense), net and other non-operating activity (K) (258,308) (208,893) (26,472)Transaction and Financing Fees (K) (14,907) (62,033) —Evaluation fees for non-core asset dispositions (K) (5,780) (2,688) —Loss on debt extinguishment (16,090) — —Corporate Restructuring — — (4,378)Lease Settlement 2,122 2,999 (6,668)Earnings Before Income Taxes $787,953 $467,913 $788,345 Total Assets: December 31, 2011 2010 2009Segment assets for total reportable business segments $11,436,808 $10,972,676 $6,894,003Segment assets for all other businesses 351,370 337,855 317,004Items excluded from segment assets: Cash and other investments (K) 39,655 16,836 65,025Recoverable income taxes — 32,528 —Deferred tax assets 648,807 659,017 498,680Bond issuance costs 49,060 51,698 689Total Consolidated Assets $12,525,700 $12,070,610 $7,775,401_________________________ (K) Excludes amounts specifically related to the gas segment.162Enterprise-Wide Disclosures:CONSOL Energy's Revenues by geographical location: For the Years Ended December 31, 2011 2010 2009United States (L) $5,070,593 $4,684,358 $4,026,619Europe 455,782 208,762 298,262South America 410,634 233,466 120,174Canada 26,613 3,251 25,056Other — 8,677 38,578Total Revenues and Freight from External Customers (M) $5,963,622 $5,138,514 $4,508,689_________________________(L) CONSOL Energy attributes revenue to individual countries based on the location of the customer.(M) CONSOL Energy has contractual relationships with certain U.S. based customers who distribute coal to international markets. CONSOL Energy's Property, Plant and Equipment by geographical location are: December 31, 2011 2010 2009United States $9,294,046 $10,095,851 $6,090,703Canada 32,370 33,400 33,587Total Property, Plant and Equipment, net $9,326,416 $10,129,251 $6,124,290NOTE 26—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:The payment obligations under the $1,500,000, 8.000% per annum notes due April 1, 2017, the $1,250,000, 8.250% per annum notes due April 1,2020, and the $250,000, 6.375% per annum notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and also fully andunconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and ExchangeCommission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantorsubsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries andcertain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all otherwholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities arereflected as parent company or guarantor company amounts for purposes of this presentation.163Income Statement for the Year Ended December 31, 2011: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $751,767 $4,678,910 $234,998 $(4,862) $5,660,813Sales—Gas Royalty Interests— 66,929 — — — 66,929Sales—Purchased Gas— 4,344 — — — 4,344Freight—Outside— — 231,536 — — 231,536Other Income (including equityearnings)876,233 58,923 63,161 26,309 (871,006) 153,620Total Revenue and OtherIncome876,233 881,963 4,973,607 261,307 (875,868) 6,117,242Cost of Goods Sold and OtherOperating Charges108,681 326,597 2,740,011 228,291 97,609 3,501,189Gas Royalty Interests’ Costs— 59,377 — — (46) 59,331Purchased Gas Costs— 3,831 — — — 3,831Related Party Activity4,767 — (25,720) 1,986 18,967 —Freight Expense— — 231,347 — — 231,347Selling, General and AdministrativeExpense— 112,339 164,179 1,485 (102,427) 175,576Depreciation, Depletion andAmortization12,194 206,821 396,979 2,403 — 618,397Interest Expense235,370 9,398 3,911 53 (388) 248,344Taxes Other Than Income950 34,023 306,450 3,037 — 344,460Abandonment of Long- LivedAssets— — 115,817 — — 115,817Transaction and Financing Fees14,907 — — — — 14,907Loss on Debt Extinguishment16,090 — — — — 16,090Total Costs392,959 752,386 3,932,974 237,255 13,715 5,329,289Earnings (Loss) Before IncomeTaxes483,274 129,577 1,040,633 24,052 (889,583) 787,953Income Tax Expense (Benefit)(149,223) 51,876 243,705 9,098 — 155,456Net Income (Loss) Attributable toCONSOL Energy Inc.Shareholders$632,497 $77,701 $796,928 $14,954 $(889,583) $632,497164Balance Sheet for December 31, 2011: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedAssets: Current Assets: Cash and Cash Equivalents$37,342 $336,727 $1,269 $398 $— $375,736Accounts and Notes Receivable: Trade— 63,299 (5,081) 404,594 — 462,812Notes Receivable2,669 311,754 527 — — 314,950Securitized— — — — — —Other2,913 91,582 7,458 3,755 — 105,708Inventories— 8,600 206,096 43,639 — 258,335Deferred Income Taxes191,689 (50,606) — — — 141,083Prepaid Expenses28,470 159,900 49,224 1,759 — 239,353Total Current Assets263,083 921,256 259,493 454,145 — 1,897,977Property, Plant and Equipment: Property, Plant and Equipment198,004 5,488,094 8,376,831 24,390 — 14,087,319Less-Accumulated Depreciation, Depletion andAmortization109,924 778,716 3,855,323 16,940 — 4,760,903Property, Plant and Equipment-Net88,080 4,709,378 4,521,508 7,450 — 9,326,416Other Assets: Deferred Income Taxes963,332 (455,608) — — — 507,724Investment in Affiliates9,126,453 96,914 760,548 — (9,801,879) 182,036Restricted Cash22,148 — — — — 22,148Notes Receivable4,148 296,344 — — — 300,492Other116,624 110,128 52,009 10,146 — 288,907Total Other Assets10,232,705 47,778 812,557 10,146 (9,801,879) 1,301,307Total Assets$10,583,868 $5,678,412 $5,593,558 $471,741 $(9,801,879) $12,525,700Liabilities and Stockholders’ Equity: Current Liabilities: Accounts Payable$140,823 $206,072 $164,521 $10,587 $— $522,003Accounts Payable (Recoverable)—Related Parties2,900,546 9,431 (3,228,229) 318,252 — —Current Portion Long-Term Debt805 5,587 13,543 756 — 20,691Accrued Income Taxes68,819 6,814 — — — 75,633Other Accrued Liabilities493,450 58,401 206,649 11,570 — 770,070Total Current Liabilities3,604,443 286,305 (2,843,516) 341,165 — 1,388,397Long-Term Debt:3,001,092 50,326 124,674 1,331 — 3,177,423Deferred Credits and Other Liabilities Postretirement Benefits Other Than Pensions— — 3,059,671 — — 3,059,671Pneumoconiosis Benefits— — 173,553 — — 173,553Mine Closing— — 406,712 — — 406,712Gas Well Closing— 61,954 62,097 — — 124,051Workers’ Compensation— — 150,786 248 — 151,034Salary Retirement269,069 — — — — 269,069Reclamation— — 39,969 — — 39,969Other98,379 16,899 9,658 — — 124,936Total Deferred Credits and Other Liabilities367,448 78,853 3,902,446 248 — 4,348,995Total CONSOL Energy Inc. Stockholders’ Equity3,610,885 5,262,928 4,409,954 128,997 (9,801,879) 3,610,885Noncontrolling Interest— — — — — —Total Liabilities and Stockholders’ Equity$10,583,868 $5,678,412 $5,593,558 $471,741 $(9,801,879) $12,525,700165Condensed Statement of Cash FlowsFor the Year Ended December 31, 2011: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by (Used in) Operating Activities$530,444 $329,360 $669,704 $(1,902) $— $1,527,606Cash Flows from Investing Activities: Capital Expenditures$(41,172) $(664,612) $(676,587) $— $— $(1,382,371)Distributions, net of Investments in, from EquityAffiliates— 50,626 5,250 — — 55,876Other Investing Activities10 746,956 (469) 1,474 — 747,971Net Cash (Used in) Provided by InvestingActivities$(41,162) $132,970 $(671,806) $1,474 $— $(578,524)Cash Flows from Financing Activities: Dividends Paid$(96,356) $— $— $— $— $(96,356)Payments on Short-Term Borrowings(155,000) (129,000) — — — (284,000)Payments on Securitization Facility(200,000) — — — — (200,000)Payments on Long Term Notes, includingredemption premium(265,785) — — — — (265,785)Proceeds from Long-Term Notes250,000 — — — — 250,000Debt Issuance and Financing Fees(10,628) (5,058) — — — (15,686)Other Financing Activities16,377 (8,104) (1,793) (793) — 5,687Net Cash (Used in) Provided by FinancingActivities$(461,392) $(142,162) $(1,793) $(793) $— $(606,140)166Income Statement for the Year Ended December 31, 2010: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $745,809 $4,002,790 $196,118 $(6,014) $4,938,703Sales—Gas Royalty Interests— 62,869 — — — 62,869Sales—Purchased Gas— 11,227 — — — 11,227Freight—Outside— — 125,715 — — 125,715Other Income (including equityearnings)565,780 5,174 51,004 29,851 (554,302) 97,507Total Revenue and OtherIncome565,780 825,079 4,179,509 225,969 (560,316) 5,236,021Cost of Goods Sold and OtherOperating Charges102,645 258,278 2,636,360 10,858 254,186 3,262,327Gas Royalty Interests’ Costs— 53,839 — — (64) 53,775Purchased Gas Costs— 9,736 — — — 9,736Related Party Activity(11,676) — (10,059) 180,398 (158,663) —Freight Expense— — 125,544 — — 125,544Selling, General and AdministrativeExpense— 92,886 134,590 1,068 (78,334) 150,210Depreciation, Depletion andAmortization10,641 190,424 363,961 2,637 — 567,663Interest Expense188,343 7,196 9,838 25 (370) 205,032Taxes Other Than Income6,599 29,882 289,160 2,817 — 328,458Transaction andFinancing Fees62,031 3,330 2 — — 65,363Total Costs358,583 645,571 3,549,396 197,803 16,755 4,768,108Earnings (Loss) Before IncomeTaxes207,197 179,508 630,113 28,166 (577,071) 467,913Income Tax Expense (Benefit)(139,584) 73,378 164,838 10,655 — 109,287Net Income (Loss)$346,781 $106,130 $465,275 $17,511 $(577,071) $358,626Less: Net Income Attributable toNoncontrolling Interest$— $— $— $— $(11,845) $(11,845)Net Income (Loss) Attributable toCONSOL Energy Inc.Shareholders$346,781 $106,130 $465,275 $17,511 $(588,916) $346,781167Balance Sheet for December 31, 2010: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedAssets: Current Assets: Cash and Cash Equivalents$11,382 $16,559 $3,235 $1,618 $— $32,794Accounts and Notes Receivable: Trade— 65,197 646 186,687 — 252,530Securitized200,000 — — — — 200,000Notes Receivable408 — — — — 408Other4,227 3,361 10,915 2,678 — 21,181Inventories— 4,456 203,962 50,120 — 258,538Recoverable Income Taxes(3,189) 35,717 — — — 32,528Deferred Income Taxes173,211 960 — — — 174,171Prepaid Expenses35,297 57,907 39,309 10,343 — 142,856Total Current Assets421,336 184,157 258,067 251,446 — 1,115,006Property, Plant and Equipment: Property, Plant and Equipment166,884 6,336,121 8,422,235 26,118 — 14,951,358Less-Accumulated Depreciation, Depletion andAmortization91,952 628,506 4,083,693 17,956 — 4,822,107Property, Plant and Equipment-Net74,932 5,707,615 4,338,542 8,162 — 10,129,251Other Assets: Deferred Income Taxes902,188 (417,342) — — — 484,846Investment in Affiliates7,833,948 23,569 952,138 11,087 (8,727,233) 93,509Restricted Cash20,291 — — — — 20,291Notes Receivable6,866 — — — — 6,866Other111,283 37,268 61,532 10,758 — 220,841Total Other Assets8,874,576 (356,505) 1,013,670 21,845 (8,727,233) 826,353Total Assets$9,370,844 $5,535,267 $5,610,279 $281,453 $(8,727,233) $12,070,610Liabilities and Stockholders’ Equity: Current Liabilities: Accounts Payable$130,063 $101,944 $113,036 $8,968 $— $354,011Accounts Payable (Recoverable)-Related Parties2,363,108 30,302 (2,543,991) 150,581 — —Short-Term Notes Payable155,000 129,000 — — — 284,000Current Portion of Long-Term Debt758 9,851 13,589 585 — 24,783Borrowings under Securitization Facility200,000 — — — — 200,000Other Accrued Liabilities302,788 59,960 425,735 13,508 — 801,991Total Current Liabilities3,151,717 331,057 (1,991,631) 173,642 — 1,664,785Long-Term Debt:3,000,702 58,905 125,627 904 — 3,186,138Deferred Credits and Other Liabilities: Postretirement Benefits Other Than Pensions— — 3,077,390 — — 3,077,390Pneumoconiosis Benefits— — 173,616 — — 173,616Mine Closing— — 393,754 — — 393,754Gas Well Closing— 60,027 70,951 — — 130,978Workers’ Compensation— — 148,265 49 — 148,314Salary Retirement161,173 — — — — 161,173Reclamation— — 53,839 — — 53,839Other112,775 25,483 6,352 — — 144,610Total Deferred Credits and Other Liabilities273,948 85,510 3,924,167 49 — 4,283,674Total CONSOL Energy Inc. Stockholders’ Equity2,944,477 5,068,259 3,543,652 106,858 (8,718,769) 2,944,477Noncontrolling Interest— (8,464) 8,464 — (8,464) (8,464)Total Liabilities and Stockholders’ Equity$9,370,844 $5,535,267 $5,610,279 $281,453 $(8,727,233) $12,070,610168Condensed Statement of Cash FlowsFor the Year Ended December 31, 2010: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by Operating Activities$93,623 $361,073 $675,627 $989 $— $1,131,312Cash Flows from Investing Activities: Capital Expenditures$— $(421,428) $(732,596) $— $— $(1,154,024)Acquisition of Dominion Exploration and ProductionBusiness— — (3,470,212) — — (3,470,212)Purchase of CNX Gas Noncontrolling Interest(991,034) — — — — (991,034)Investment in Equity Affiliates(3,470,212) 1,501 9,951 — 3,470,212 11,452Other Investing Activities— 562 59,282 — — 59,844Net Cash Used in Investing Activities$(4,461,246) $(419,365) $(4,133,575) $— $3,470,212 $(5,543,974)Cash Flows from Financing Activities: Dividends Paid$(85,861) $— $— $— $— $(85,861)(Payments on) Proceeds from Short-TermBorrowings(260,000) 71,150 — — — (188,850)Proceeds from Securitization Facility150,000 — — — — 150,000Proceeds from Long-Term Notes2,750,000 — — — — 2,750,000Proceeds from Issuance of Common Stock1,828,862 — — — — 1,828,862Proceeds from Parent— — 3,470,212 — (3,470,212) —Debt Issuance and Financing Fees(84,248) — — — — (84,248)Other Financing Activities20,703 2,577 (12,793) (541) — 9,946Net Cash Provided by (Used in) FinancingActivities$4,319,456 $73,727 $3,457,419 $(541) $(3,470,212) $4,379,849169Income Statement for the Year Ended December 31, 2009: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $630,598 $3,487,022 $197,350 $(3,179) $4,311,791Sales—Gas Royalty Interests— 40,951 — — — 40,951Sales—Purchased Gas— 7,040 — — — 7,040Freight—Outside— — 148,907 — — 148,907Other Income (including equityearnings)622,216 4,855 76,442 22,173 (612,500) 113,186Total Revenue and Other Income622,216 683,444 3,712,371 219,523 (615,679) 4,621,875Cost of Goods Sold and Other OperatingCharges84,960 188,454 2,050,591 190,854 242,193 2,757,052Gas Royalty Interests’ Costs— 32,423 — — (47) 32,376Purchased Gas Costs— 6,442 — — — 6,442Related Party Activity7,052 — 132,106 1,495 (140,653) —Freight Expense— — 148,907 — — 148,907Selling, General and AdministrativeExpense— 66,655 151,158 1,287 (88,396) 130,704Depreciation, Depletion andAmortization13,022 107,251 316,352 2,654 (1,862) 437,417Interest Expense13,229 7,568 10,959 15 (352) 31,419Taxes Other Than Income9,576 12,590 265,180 2,595 — 289,941Black Lung Excise Taxes— — (728) — — (728)Total Costs127,839 421,383 3,074,525 198,900 10,883 3,833,530Earnings (Loss) Before Income Taxes494,377 262,061 637,846 20,623 (626,562) 788,345Income Tax Expense (Benefit)(45,340) 98,636 160,105 7,802 — 221,203Net Income (Loss)539,717 163,425 477,741 12,821 (626,562) 567,142Less: Net Income Attributable toNoncontrolling Interest— 1,037 (1,037) — (27,425) (27,425)Net Income (Loss) Attributable toCONSOL Energy Inc. Shareholders$539,717 $164,462 $476,704 $12,821 $(653,987) $539,717170Condensed Statement of Cash FlowsFor the Year Ended December 31, 2009: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by (Used in) Operating Activities$179,095 $360,163 $523,596 $(2,403) $— $1,060,451Cash Flows from Investing Activities: Capital Expenditures$— $(336,447) $(583,633) $— $— $(920,080)Investment in Equity— 1,250 3,605 — — 4,855Other Investing Activities— 288 69,596 — — 69,884Net Cash (Used in) Provided by InvestingActivities$— $(334,909) $(510,432) $— $— $(845,341)Cash Flows from Financing Activities: Dividends Paid$(72,292) $— $— $— $— $(72,292)Payments on Short-Term Borrowings(70,000) (14,850) — — — (84,850)Payments on Securitization Facility(115,000) — — — — (115,000)Other Financing Activities5,275 (11,206) (9,481) (461) — (15,873)Net Cash (Used in) Provided by FinancingActivities$(252,017) $(26,056) $(9,481) $(461) $— $(288,015)NOTE 27—RELATED PARTY TRANSACTIONSCONE Gathering LLC Related Party TransactionsDuring the year ended December 31, 2011, CONE Gathering LLC (CONE), a 50% owned affiliate, provided CNX Gas Company LLC (CNX GasCompany) gathering services in the ordinary course of business. Gathering services received from CONE were $4,267. In addition, CONSOL Energy andCNX Gas Company provide various administrative support functions to CONE. CONSOL Energy and CNX Gas Company are reimbursed by CONE forthese support services. Services provided by CNX Gas Company were $592 for the year ended December 31, 2011. During the start-up phase of this joint-venture, CNX Gas Company also provided treasury support functions including making all required payments to vendors on behalf of CONE. Payments tovendors on behalf of CONE were $12,743 for the year ended December 31, 2011.As of December 31, 2011, CONSOL Energy and CNX Gas had a net receivable of $8,966 due from CONE which is comprised of the followingitems: December 31, 2011 Location on Balance SheetCONE Gathering Capital Reimbursement$8,042 Accounts Receivable–OtherReimbursement for CONE Expenses2,009 Accounts Receivable–OtherReimbursement for Services Provided to CONE414 Accounts Receivable–OtherCONE Gathering Fee Payable(1,499) Accounts PayableNet Receivable due from CONE$8,966 171Supplemental Coal Data (unaudited) Millions of Tons For the Year Ended December 31, 2011 2010 2009 2008 2007Proved and probable reserves at beginning of period.................................... 4,401 4,520 4,543 4,526 4,272Purchased reserves......................................................................................... 6 4 5 — 177Reserves sold in place.................................................................................... — (41) (3) (12) (33)Production...................................................................................................... (63) (63) (59) (65) (65)Revisions and other changes.......................................................................... 115 (19) 34 94 175Consolidated proved and probable reserves at end of period*...................... 4,459 4,401 4,520 4,543 4,526Proportionate share of proved and probable reserves of unconsolidated equityaffiliates*......................................................................................... 145 172 170 171 179______________*Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. GeologicalSurvey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2011, 742 million tonswere assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2011 include3,838 million tons of steam coal reserves, of which approximately 7 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per millionBritish thermal unit (Btu), 15 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu and an additional 78percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million BTU. The reserves also include 621 million tons of metallurgicalcoal in consolidated reserves, of which approximately 64 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and anadditional 36 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgicalcoal can also serve the steam coal market.Supplemental Gas Data (unaudited):The following information was prepared in accordance with the Financial Accounting Standards Board's Accounting Standards Update No. 2010-03,“Extractive Activities-Oil and Gas (Topic 932).”Capitalized Costs: As of December 31, 2011 2010Proven properties $1,495,772 $1,615,540Unproven properties 1,258,455 2,206,827Wells and related equipment 1,755,617 1,558,300Gathering assets 963,494 941,772Total Property, Plant and Equipment 5,473,338 6,322,439Accumulated Depreciation, Depletion and Amortization (773,027) (623,575)Net Capitalized Costs $4,700,311 $5,698,864172Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2011 2010 2009Property acquisitions Proven properties $6,673 $1,476,470 $30,405Unproven properties 58,731 1,922,334 50,705Development 463,401 472,691 181,944Exploration 131,419 58,655 46,023Total $660,224 $3,930,150 $309,077__________(*)Includes costs incurred whether capitalized or expensed.Results of Operations for Producing Activities: For the Years Ended December 31, 2011 2010 2009Production Revenue $751,767 $745,809 $630,598Royalty Interest Gas Revenue 66,929 62,869 40,951Purchased Gas Revenue 4,344 11,227 7,040Total Revenue 823,040 819,905 678,589Lifting Costs 131,184 87,155 55,285Gathering Costs 142,339 127,927 95,687Royalty Interest Gas Costs 59,377 53,839 32,423Other Costs 62,302 63,941 45,795Purchased Gas Costs 3,831 9,736 6,442DD&A 206,821 190,424 107,251Total Costs 605,854 533,022 342,883Pre-tax Operating Income 217,186 286,883 335,706Income Taxes 86,961 117,278 125,890Results of Operations for Producing Activities excluding Corporate and InterestCosts $130,225 $169,605 $209,816The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production: For the Years Ended December 31, 2011 2010 2009Production in million cubic feet 153,504 127,875 94,415Average gas sales price before effects of financial settlements (per thousand cubic feet) $4.27 $4.53 $4.15Average effects of financial settlements (per thousand cubic feet) $0.63 $1.30 $2.53Average gas sales price including effects of financial settlements (per thousand cubic feet) $4.90 $5.83 $6.68Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet) $0.68 $0.50 $0.48During the years ended December 31, 2011, 2010 and 2009, we drilled 254.9, 317 and 247 net development wells, respectively. There were no net drydevelopment wells in 2011, one net dry development well in 2010 and one net dry development well in 2009.During the years ended December 31, 2011, 2010 and 2009, we drilled 69.5, 38 and 18 net exploratory wells, respectively.173There were two net dry exploratory wells in 2011, two net dry exploratory wells in 2010 and one net dry exploratory well in 2009.At December 31, 2011, there were 47 net development wells in the process of being drilled.At December 31, 2011, there were 2.5 net exploratory wells in the process of being drilled.CONSOL Energy is committed to provide 89.8 bcf of gas under existing sales contracts or agreements over the course of the next four years. CONSOLEnergy expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term,but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The followingtable sets forth, at December 31, 2011, the number of producing wells, developed acreage and undeveloped acreage: Gross Net(1)Producing Wells (including gob wells) 14,743 12,725Proved Developed Acreage 507,949 421,874Proved Undeveloped Acreage 146,479 124,276Unproved Acreage 5,035,749 4,040,598 Total Acreage 5,690,177 4,586,748____________(1)Net acres include acreage attributable to our working interests of the properties. Additional adjustments (either increases or decreases) may be required aswe further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that ourassumptions and methodology in this regard are reasonable.Proved Oil and Gas Reserve Quantities:The preparation of our gas reserve estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures, which includeverification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technicalemployee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2011 gas reserve results were audited by NetherlandSewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer. The gas reserve estimates are asfollows: Consolidated Operations 2011 2010 2009Net Reserve Quantity (MMcfe) Beginning reserves 3,731,597 1,911,391 1,422,046Revisions(a) (83,813) 379,977 177,004Extensions and discoveries(b) 517,178 621,270 406,756Production (153,504) (127,875) (94,415)Purchases of reserves in-place — 946,834 —Sale of reserves in-place (531,431) — —Ending reserves(c) 3,480,027 3,731,597 1,911,391__________(a)Revisions are due to price, efficiencies in operations, and changes in the current five year plan as well as a comprehensive look into reservoircharacterization and well performance.(b)Extensions and Discoveries are due to the drilling of proved undeveloped, probable and possible locations adhering to Security and ExchangeCommission (SEC) guidelines on booking PUD locations if reliable technology can be demonstrated. The reliable technologies that were utilized includewire line open-hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized productionperformance 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 becommercially recovered under current economic conditions, operating methods and government174regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future productionrates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions andgovernment regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment andoperating methods. 2011 2010 2009 All Natural Oil All Natural Oil All Natural Oil Products Gas mmcf mmcfe (a) Products Gas mmcf mmcfe (a) Products Gas mmcf mmcfe (a)Proved developed reserves(consolidated entities only) Beginning of year 1,931,272 1,924,036 7,236 1,040,257 1,039,052 1,205 783,290 783,010 280End of year 2,135,805 2,126,330 9,475 1,931,272 1,924,036 7,236 1,040,257 1,039,052 1,205 Proved undeveloped reserves(consolidated entities only) Beginning of year 1,800,325 1,800,325 — 871,134 871,134 — 638,756 638,756 —End of year 1,344,222 1,344,222 — 1,800,325 1,800,325 — 871,134 871,134 —_________(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 millionbarrels of oil. For the Year Ended December 31, 2011Proved Undeveloped Reserves (MMcfe) Beginning proved undeveloped reserves 1,800,325Undeveloped reserves transferred to developed(a) (200,849)Disposition of reserves in place (278,581)Revisions (362,770)Extension and discoveries 386,097Ending proved undeveloped reserves(b) 1,344,222_________(a)During 2011, various exploration and development drilling and evaluations were completed. Approximately, $134,064 of capital was spent in the yearended 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 fiveyears. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity createdby the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take asignificant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports thecontinual operation of the mine for many years past, unless there was an extreme circumstance which resulted from an external factor. These reasonsconstitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.The following table represents the capitalized exploratory well cost activity as indicated:175 December 31, 2011Costs pending the determination of proved reserves at December 31, 2011(a) Less than one year $—More than one year but less than five years 3,309More than five years 2,171 Total $5,480__________(a)Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned explorationexpenditures 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. December 31, 2011 2010 2009Costs reclassified to wells, equipment and facilities based on the determination of provedreserves $189 $93,482 $52,332Costs expensed due to determination of dry hole or abandonment of project $5,108 $9,614 $8,194CONSOL Energy's proved gas reserves are located in the United States.Standardized Measure of Discounted Future Net Cash Flows:The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board's Accounting StandardsUpdate No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to bebased on the average, first-day-of-the-month price for the year ended December 31, 2011. Because prices used in the calculation are average prices for thatyear, the standardized measure could vary significantly from year to year based on the market conditions that occurred.The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representingcurrent value to CONSOL Energy. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves maynot occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CONSOL Energy'sinvestment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as provedreserves and on a different price and cost assumptions.The standardized measure is intended to provide a better means for comparing the value of CONSOL Energy's proved reserves at a given time withthose of other gas producing companies than is provided by a comparison of raw proved reserve quantities. December 31, 2011 2010 2009Future Cash Flows: Revenues $14,804,398 $16,723,795 $7,975,195Production costs (5,262,635) (5,175,563) (3,123,532)Development costs (1,674,829) (2,720,243) (995,569)Income tax expense (2,989,435) (3,354,444) (1,465,075)Future Net Cash Flows 4,877,499 5,473,545 2,391,019Discounted to present value at a 10% annual rate (3,130,318) (3,812,724) (1,496,668)Total standardized measure of discounted net cash flows $1,747,181 $1,660,821 $894,351The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during:176 December 31, 2011 2010 2009Balance at beginning of period $1,660,821 $894,351 $1,218,434Net changes in sales prices and production costs (339,098) 721,997 (457,138)Sales net of production costs (217,186) (286,883) (335,706)Net change due to revisions in quantity estimates (83,580) 414,704 189,583Net change due to extensions, discoveries and improved recovery 324,755 326,584 124,008Net change due to (divestiture) acquisition (559,132) 500,376 —Development costs incurred during the period 463,401 295,142 181,944Difference in previously estimated development costs compared to actual costs incurredduring the period 154,137 (12,060) (3,282)Changes in estimated future development costs 155,619 (426,870) (380,639)Net change in future income taxes 130,746 (612,114) 248,639Accretion of discount and other 56,698 (154,406) 108,508 Total discounted cash flow at end of period $1,747,181 $1,660,821 $894,351Supplemental Quarterly Information (unaudited):(Dollars in thousands, except per share data) Three Months Ended March 31, June 30, September 30, December 31, 2011 2011 2011 2011Sales $1,405,293 $1,503,435 $1,439,930 $1,383,431Freight Revenue $36,868 $59,572 $59,871 $75,225Cost of Goods Sold and Other Operating Charges (including GasRoyalty Interests' Costs and Purchased Gas Costs) $831,192 $943,541 $895,075 $894,543Freight Expense $36,679 $59,572 $59,871 $75,225Net Income $192,149 $77,384 $167,329 $195,635Net Income Attributable to CONSOL Energy Inc Shareholders $192,149 $77,384 $167,329 $195,635Total Earnings per Share Basic $0.85 $0.34 $0.74 $0.86Diluted $0.84 $0.34 $0.73 $0.85Weighted Average Shares Outstanding Basic 226,350,594 226,647,752 226,744,011 226,971,597Diluted 228,814,838 229,138,024 229,163,537 229,314,370177 Three Months Ended March 31, June 30, September 30, December 31, 2010 2010 2010 2010Sales $1,186,869 $1,236,007 $1,282,154 $1,307,769Freight Revenue $31,200 $28,075 $37,269 $29,171Cost of Goods Sold and Other Operating Charges (including GasRoyalty Interests' Costs and Purchased Gas Costs) $781,367 $831,638 $870,560 $842,273Freight Expense $31,200 $28,075 $37,269 $29,000Net Income $107,882 $70,900 $75,383 $104,461Net Income Attributable to CONSOL Energy Inc Shareholders $100,269 $66,668 $75,383 $104,461Total Earnings per Share Basic $0.55 $0.30 $0.33 $0.46Diluted $0.54 $0.29 $0.33 $0.46Weighted Average Shares Outstanding Basic 181,726,480 225,715,539 225,781,539 225,854,413Diluted 184,348,982 228,081,103 228,092,299 228,169,569178ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURESNone.ITEM 9A.CONTROLS AND PROCEDURESDisclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOLEnergy’s principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” assuch term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this AnnualReport on Form 10-K. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that theCompany’s disclosure controls and procedures are effective as of December 31, 2011 to ensure that information required to be disclosed by CONSOL Energyin reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities andExchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by CONSOLEnergy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer andprincipal financial officer, as appropriate, to allow timely decisions regarding required disclosure.Management's Annual Report on Internal Control Over Financial Reporting. CONSOL Energy's management is responsible for establishingand maintaining adequate internal control over financial reporting. CONSOL Energy's internal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance withgenerally accepted accounting principles.CONSOL Energy's internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures arebeing made only in accordance with authorizations of management and the directors of CONSOL Energy; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use or disposition of CONSOL Energy's assets that could have a material effect on our financialstatements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluationof effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.Management assessed the effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2011. In making thisassessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that CONSOL Energy maintained effective internal controlover financial reporting as of December 31, 2011.The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2011 has been audited by Ernst and Young, anindependent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II,Item 9a of this annual report on Form 10-K.Changes in internal controls over financial reporting. There were no changes in the Company's internal controls over financial reporting thatoccurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely tomaterially affect, the Company’s internal control over financial reporting.179Report of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of CONSOL Energy Inc. and SubsidiariesWe have audited CONSOL Energy Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria establishedin Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CONSOLEnergy Inc. and Subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of theeffectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control Over FinancialReporting appearing under Item 9a. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluationof effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.In our opinion, CONSOL Energy Inc. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2011, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balancesheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders' equity,and cash flows for each of the three years in the period ended December 31, 2011 of CONSOL Energy Inc. and Subsidiaries and our report dated February10, 2012 expressed an unqualified opinion thereon./s/ Ernst & Young LLPPittsburgh, PennsylvaniaFebruary 10, 2012180ITEM 9B.OTHER INFORMATIONNone.PART IIIITEM 10.DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEThe information required by this Item is incorporated herein by reference from the information under the captions “PROPOSAL NO. 1-ELECTION OFDIRECTORS-Biographies of Directors,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITSCOMMITTEES-Corporate Governance Web Page and Available Documents,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES–Audit Committee”, "BOARD OF DIRECTORS AND COMPENSATION INFORMATION -BOARD OF DIRECTORS AND ITS COMMITTEES - Membership and Meetings of the Board of Directors and its Committees," and “SECTION 16(A)BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 1, 2012 (the“Proxy Statement”).Executive Officers of CONSOL EnergyThe following is a list of CONSOL Energy executive officers, their ages as of February 10, 2012 and their positions and offices held with CONSOLEnergy.Name Age PositionJ. Brett Harvey 61 Chairman of the Board and Chief Executive OfficerNicholas J. DeIuliis 43 PresidentWilliam J. Lyons 63 Executive Vice President and Chief Financial OfficerP. Jerome Richey 62 Executive Vice President - Corporate Affairs, Chief Legal Officer and SecretaryRobert P. King 59 Executive Vice President - Business Advancements and Support ServicesRobert F. Pusateri 61 Executive Vice President - Energy Sales and Transportation ServicesJ. Brett Harvey has been Chief Executive Officer and a Director of CONSOL Energy since January 1998. He was elected Chairman of the Board ofCONSOL Energy on June 29, 2010. Mr. Harvey was the President of CONSOL Energy from January 1998 until February 23, 2011. He has been a Directorof CNX Gas Corporation since June 30, 2005 and he became Chairman of the Board and Chief Executive Officer of CNX Gas Corporation on January 16,2009. Mr. Harvey is a Director of Barrick Gold Corporation, the world's largest gold producer, and Allegheny Technologies Incorporated, a specialty metalsproducer.Nicholas J. DeIuliis has been President of CONSOL Energy since February 23, 2011. He was Executive Vice President and Chief Operating Officer ofCONSOL from January 16, 2009 until February 23, 2011. Prior to that time, Mr. DeIuliis served as Senior Vice President - Strategic Planning of CONSOLEnergy from November 2004 until August 2005, Vice President Strategic Planning from April 2002 until November 2004, Director-Corporate Strategy fromOctober 2001 until April 2002, Manager-Strategic Planning from January 2001 until October 2001 and Supervisor-Process Engineering from April 1999 untilJanuary 2001. He resigned from his position with CONSOL Energy as of August 8, 2005. He was a Director and President and Chief Executive Officer ofCNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX Gas Corporation, a positionwhich he continues to hold.William J. Lyons has been Chief Financial Officer of CONSOL Energy since February 2001 and Chief Financial Officer of CNX Gas Corporationsince April 28, 2008. He added the title of Executive Vice President of CONSOL Energy on May 2, 2005 and of CNX Gas Corporation on January 16, 2009.From January 1995 until February 2001, Mr. Lyons held the position of Vice President-Controller for CONSOL Energy. Mr. Lyons joined CONSOL Energyin 1976. He was a Director of CNX Gas Corporation from October 17, 2005 to January 16, 2009. Mr. Lyons is a director of Calgon Carbon Corporation, asupplier of products and services for purifying water and air.P. Jerome Richey became Executive Vice President-Corporate Affairs and Chief Legal Officer of CONSOL Energy and CNX Gas Corporation onJanuary 16, 2009. He was Vice President, General Counsel and Corporate Secretary of CONSOL Energy since March 2005, and on June 20, 2007, he addedthe title of Senior Vice President. Prior to joining CONSOL Energy, Mr. Richey, for more than five years, was a shareholder in the Pittsburgh office for the lawfirm of Buchanan Ingersoll & Rooney PC.181Robert P. King became Executive Vice President-Business Advancement and Support Services of CONSOL Energy and CNX Gas Corporation onJanuary 16, 2009. Prior to that, he was Senior Vice President-Administration since February 2, 2007 and he served as Vice President-Land from August 2006to February 2007. Prior to joining CONSOL Energy, Mr. King was Vice President of Interwest Mining Company (a subsidiary of PacifiCorp). Mr. Kingjoined PacifiCorp in November 1990.Robert F. Pusateri became Executive Vice President-Energy Sales and Transportation Services of CONSOL Energy and CNX Gas Corporation onJanuary 16, 2009 and President of CNX Land Resources Inc. on September 13, 2011. Prior to that, he was named Vice President Sales of CONSOL Energyin 1996 and held that position until he was elected President of CONSOL Energy Sales Company in August 2005. He first became an officer in May 1996.CONSOL Energy has a written Code of Business Conduct that applies to CONSOL Energy's Chief Executive Officer (Principal Executive Officer),Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is available on CONSOL Energy's website atwww.consolenergy.com. Any amendments to, or waivers from, a provision of our code of employee business conduct and ethics that applies to our principalexecutive officer, our principal financial and accounting officer and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 ofRegulation S-K shall be disclosed by posting such information on our website.By certification dated June 1, 2011, CONSOL Energy's Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was notaware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302certifications regarding the quality of our public disclosures were filed by CONSOL Energy as exhibits to this Form 10-K.ITEM 11.EXECUTIVE COMPENSATIONThe information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS ANDCOMPENSATION INFORMATION-DIRECTOR COMPENSATION TABLE-2011,” “BOARD OF DIRECTORS AND COMPENSATIONINFORMATION-UNDERSTANDING OUR DIRECTOR COMPENSATION TABLE,” and “EXECUTIVE COMPENSATION AND STOCK OPTIONINFORMATION” in the Proxy Statement.ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERSThe information required by this Item is incorporated by reference from the information under the caption “BENEFICIAL OWNERSHIP OFSECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGY EQUITY COMPENSATION PLAN” in the ProxyStatement.ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEThe information requested by this Item is incorporated by reference from the information under the caption “PROPOSAL NO. 1-ELECTION OFDIRECTORS-Related Party Policy and Procedures” and “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Determination of Director Independence” in theProxy Statement.ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICESThe information required by this Item is incorporated by reference from the information under the caption “ACCOUNTANTS AND AUDITCOMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” in the Proxy Statement.182PART IVITEM 15.EXHIBIT INDEXIn reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that such agreements are included toprovide information regarding their terms. They are not intended to be a source of financial, business or operational information about CONSOL Energy orany of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of theagreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by theparties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the partiesinstead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable toinvestors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof ascharacterizations of the actual state of facts or condition of CONSOL Energy or any of its subsidiaries or affiliates or, in connection with acquisitionagreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may changeafter the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they weremade or at any other time.(A)(1) Financial Statements Contained in Item 8 hereof.(A)(2) Financial Statement Schedule–Schedule II Valuation and qualifying accounts.2.1 Purchase and Sale Agreement, dated as of March 14, 2010, among Dominion Resources, Inc., Dominion Transmission, Inc., Dominion Energy,Inc. and CONSOL Energy Holdings LLC VI, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on March 16,2010.2.2 Parent Guarantee, dated March 14, 2010, by and among CONSOL Energy Inc. and Dominion Resources, Inc., Dominion Transmission, Inc.and Dominion Energy, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.2.3 Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc., incorporated by reference toExhibit 2.1 to Form 8-K (file no. 001-14901) filed on August 18, 2011.2.4 Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated byreference to Exhibit 2.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.3.1 Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed onMay 8, 2006.3.2 Amended and Restated Bylaws of CONSOL Energy Inc., dated as of February 23, 2011, incorporated by reference to Exhibit 3.2 to Form 8-K(file no. 001-14901) filed on March 1, 2011.4.1 Indenture, dated as of April 1, 2010, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and The Bank of Nova ScotiaTrust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K(file no. 001-14901) filed on April 2, 2010.4.2 Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., DominionCoalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL EnergyInc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated byreference to Exhibit 4.4 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.4.3 Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX GasCorporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia TrustCompany of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.5 to Form 8-K/A(file no. 001-14901) filed on August 6, 2010.4.4 Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certainsubsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% SeniorNotes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on August 29, 2011.4.5 Indenture, dated as of April 1, 2010, among CONSOL Energy, Inc., the Subsidiary Guarantors named therein and The Bank of Nova ScotiaTrust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 2, 2010.1834.6 Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., DominionCoalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL EnergyInc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated byreference to Exhibit 4.6 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.4.7 Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX GasCorporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia TrustCompany of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.7 to Form 8-K/A(file no. 001-14901) filed on August 6, 2010.4.8 Supplemental Indenture No. 3, dated as of August 24, 2011, to Indenture dated as of April 1, 2010 among CONSOL Energy Inc., certainsubsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.250%Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on August 29, 2011.4.9 Indenture, dated as of March 9, 2011, among CONSOL Energy Inc., the Subsidiaries named therein and The Bank of Nova Scotia TrustCompany of New York, as trustee, with respect to the 6.375% Senior Notes due 2021, incorporated by reference to Exhibit 4.1 to Form 8-K (fileno. 001-14901) filed on March 11, 2011.4.10 Supplemental Indenture No. 1, dated as of August 24, 2011, to Indenture dated as of March 9, 2011 among CONSOL Energy Inc., certainsubsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 6.375%Senior Notes due 2021, incorporated by reference to Exhibit 4.3 to Form 8-K (file no. 001-14901) filed on August 29, 2011.4.11 Rights Agreement, dated as of December 22, 2003, between CONSOL Energy Inc., and Equiserve Trust Company, N.A., as Rights Agent,incorporated by reference to Exhibit 4 to Form 8-K (file no. 001-14901) filed on December 22, 2003.4.12 Registration Rights Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc., the Guarantors listed on Schedule I attachedthereto and Banc of America Securities LLC, as Representative of the Initial Purchasers, incorporated by reference to Exhibit 4.3 to From 8-K(file no. 001-14901) filed on April 2, 2010.4.13 Registration Rights Agreement, dated as of March 9, 2011, by and among CONSOL Energy Inc., the Guarantors listed on Schedule I attachedthereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representative of the Initial Purchasers, incorporated by reference to Exhibit4.2 to Form 8-K (file no. 001-14901) filed on March 11, 2011.10.1 Purchase and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales Company, CONSOL ofKentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company,McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Gas Company LLC, CNX MarineTerminals Inc. and CNX Funding Corporation, incorporated by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarterended June 30, 2003, filed on August 13, 2003.10.2 First Amendment to Purchase and Sale Agreement dated as of April 30, 2007, entered into among CONSOL Energy Inc., CONSOL EnergySales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek CoalCompany, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNXMarine Terminals Inc., each an “Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for theyear ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.3 Second Amendment to Purchase and Sale Agreement dated as of November 16, 2007, entered into among CONSOL Energy Inc. (“CONSOLEnergy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol Pennsylvania Coal Company LLC, Consolidation CoalCompany, Island Creek Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company andCNX Marine Terminals Inc. (each an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little EagleCoal Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc., and Twin RiversTowing Company (each, a “New Originator” and collectively the “New Originators”; the Existing Originators and the New Originators, each an“Originator” and collectively, the “Originators”), Windsor Coal Company (the “Released Originator”) and CNX Funding Corporation,incorporated by reference to Exhibit 10.32 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.4 Third Amendment to the Purchase and Sale Agreement, dated as of March 12, 2010, among CNX Marine Terminals Inc., CONSOL EnergyInc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company LLC, Consolidated CoalCompany, Eighty-Four Mining Company, Fola Coal Company, L.L.C., Island Creek Coal Company, Keystone Coal Mining Corporation,Little Eagle Coal Company, L.L.C., McElroy Coal Company, Mon River Towing, Inc., Terry Eagle Coal Company, L.L.C., Twin RiversTowing Company and CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March16, 2010.18410.5 Purchase Agreement, dated as of March 25, 2010, among CONSOL Energy Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, asrepresentative of the several underwriters named in Schedule A thereto, incorporated by reference to Exhibit 1.1 to the Form 8-K (file no. 001-14901) filed on March 31, 2010.10.6 Services Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc. and its subsidiaries (other than CNX Gas Corporation andits subsidiaries) and (b) CNX Gas Corporation and its subsidiaries, incorporated by reference to Exhibit 99(D)(11) of the Schedule TO filed onApril 28, 2010.10.7 Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding Corporation, CONSOLEnergy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation CoalCompany, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-FourMining Company, CNX Marine Terminals Inc., Market Street Funding LLC, Liberty Street Funding LLC, PNC Bank, National Association,and the Bank of Nova Scotia, incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.8 First Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 9, 2007, entered into among CNX FundingCorporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agentslisted on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank, National Association, asAdministrator and as LC Bank, incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.9 Second Amendment to Amended and Restated Receivables Purchase Agreement, dated as of July 27, 2007, entered into among CNX FundingCorporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”), the Conduit Purchasers listed on the signaturepages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto and PNC Bank,National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.35 to Form 10-K for the year endedDecember 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.10 Third Amendment to Amended and Restated Receivables Purchase Agreement, dated as of November 16, 2007, entered into among CNXFunding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers listed on the signature pages thereto, theConduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed onthe signature pages thereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.36to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.11 Fourth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2009, among CNX Funding Corporation,CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed onthe signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto,and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on March 16, 2010.10.12 Fifth Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12, 2010, among CNX FundingCorporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the ConduitPurchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on thesignature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 toForm 8-K (file no. 001-14901) filed on March 16, 2010.10.13 Sixth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 23, 2010, among CNX Funding Corporation,CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the ConduitPurchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LCParticipants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank,incorporated by reference to Exhibit 10.13 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.10.14 Commitment Letter, dated March 14, 2010, among Banc of America Bridge LLC, Banc of America Securities LLC, PNC Bank, NationalAssociation PNC Capital Markets LLC and CONSOL Energy Inc., incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901)filed on March 16, 2010.10.15 Share Tender Agreement, dated as of March 21, 2010, by and between CONSOL Energy Inc., and T. Rowe Price Associates, Inc., incorporatedby reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 22, 2010 (Film No. 10695706).10.16 Amended and Restated Credit Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., the Lenders Party thereto, PNCBank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, TheRoyal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC and Banc of AmericaSecurities LLC, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 13, 2010.18510.17 Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CONSOL Energy Inc., the Guarantors Party thereto, theLenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, TheBank of Nova Scotia, The Royal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital MarketsLLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K(file no. 001-14901) filed on April 18, 2011.10.18 Amended and Restated Collateral Trust Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc. and its DesignatedSubsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference toExhibit 2.2 to Form 8-K (file no. 001-14901) filed on May 13, 2010.10.19 Amended and Restated Pledge Agreement, dated as of May 7, 2010, made and entered into by each of the pledgors listed on the signature pagesthereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and WilmingtonTrust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on May 13, 2010.10.20 Amended and Restated Security Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., each of the parties listed on thesignature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise andWilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on May 13,2010.10.21 Patent, Trademark and Copyright Security Agreement, dated as of June 27, 2007, by and among each of the pledgors listed on the signaturepages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption, or otherwise andWilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 10.20 to Form 10-K for the year ended December 31,2010 (file no. 001-14901), filed on February 10, 2011.10.22 First Amendment to Amended and Restated Patent, Trademark and Copyright Security Agreement, dated as of May 7, 2010, by and amongeach of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time byjoinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K(file no. 001-14901) filed on May 13, 2010.10.23 Patent, Trademark and Copyright Assignment and Assumption, dated as of April 12, 2011, between Wilmington Trust Company as assignorand PNC Bank, National Association as assignee, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on April 18,2011.10.24 Guaranty and Suretyship Agreement, dated as of April 30, 2003, by CONSOL Energy Inc., as guarantor in favor of CNX FundingCorporation, incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2011, filed on May 3,2011.10.25 Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of May 7, 2010, jointly and severally given by each of theundersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, NationalAssociation, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and Restated Credit Agreement,as defined therein, incorporated by reference to Exhibit 10.22 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed onFebruary 10, 2011.10.26 Continuing Agreement of Guaranty and Suretyship (CNX Gas and Certain of its Subsidiaries), dated as of June 16, 2010, jointly and severallygiven by each of the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNCBank, National Association, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and RestatedCredit Agreement, as defined therein, incorporated by reference to Exhibit 10.23 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.10.27 CNX Gas Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CNX Gas Corporation and certain of itssubsidiaries, incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.28 Successor Agent Agreement, dated as of April 12, 2011, by and among among Wilmington Trust Company and David A. Varansky as existingagents, PNC Bank, National Association as Collateral Trustee and CONSOL Energy Inc. and certain of its subsidiaries, incorporated byreference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.29 Credit Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, the guarantors party thereto, the lender parties thereto, PNCBank National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, TheRoyal Bank of Scotland PLC and Wells Fargo Bank, National Association, as the Co-Documentation Agents and PNC Capital Markets, Inc.and Bank of America Securities LLC, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 10.36 to the CNX GasCorporation Form 8-K (file no. 001-32723) filed on May 13, 2010.10.30 First Amendment to Credit Agreement, dated as of March 1, 2011, by and among CNX Gas Corporation, the Guarantors party thereto, theCONSOL Loan Parties, the Required Lenders, Bank of America, N.A., as Syndication Agent and PNC Bank, National Association as theAdministrative Agent, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2011, filedon May 3, 2011.18610.31 Amended and Restated Credit Agreement, dated as of April 12, 2011, by and among CNX Gas Corporation, the Guarantors Party thereto, theLenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, TheBank of Nova Scotia, The Royal Bank of Scotland PLC and Wells Fargo Bank, N.A., as the Co-Documentation Agents, and PNC CapitalMarkets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Bookrunners and Joint Lead Arrangers, incorporated by reference toExhibit 10.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.32 Amendment No. 1 to Credit Agreement, dated as of December 14, 2011, by and among CNX Gas Corporation, the lenders and agents partythereto and PNC Bank, National Association, as Administrative Agent.10.33 Collateral Trust Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, its Designated Subsidiaries, Wilmington TrustCompany, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.1 to the CNX GasCorporation Form 8-K (file no. 001-32723) filed on May 13, 2010.10.34 Pledge Agreement, dated as of May 7, 2010, by each of the pledgors listed on the signature pages thereto and each of the other persons andentities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as CollateralTrustee, incorporated by reference to Exhibit 2.2 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.10.35 Security Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation and each of the undersigned parties thereto and each of theother persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, asCollateral Trustee, incorporated by reference to Exhibit 2.3 to the CNX Gas Corporation Form 8-K (file no. 001-32723) filed on May 13, 2010.10.36 CONSOL Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, by CONSOL Energy andcertain of its subsidiaries, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.37 Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of April 12, 2011, among CNX Gas Company LLC andcertain of its subsidiaries, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.38 Successor Agent Agreement, dated as of April 12, 2011, by and among Wilmington Trust Company and David A. Varansky as existing agents,PNC Bank, National Association as Collateral Trustee and CNX Gas Corporation and certain of its subsidiaries, incorporated by reference toExhibit 2.3 to Form 8-K (file no. 001-14901) filed on April 18, 2011.10.39 Closing Agreement by and between CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated by referenceto Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2011, filed on October 31, 2011.10.40 Employment Agreement, dated December 2, 2008, between CONSOL Energy Inc. and J. Brett Harvey incorporated by reference to Exhibit 10.14to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.41 Time Sharing Agreement, dated as of May 1, 2007, by and between CONSOL Energy Inc. and J. Brett Harvey, incorporated by reference toExhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 7, 2007.10.42 Consulting Agreement dated, as July 1, 2010, by and between CONSOL Energy Inc., and John Whitmire, incorporated by reference to Exhibit10.1 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2010, filed on November 1, 2010.10.43 Agreement, dated September 12, 2007, by and between CONSOL Energy Inc. and Bart Hyita, regarding CONSOL Energy Inc. SupplementalRetirement Plan, incorporated by reference to Exhibit 10.112 of Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2007, filedon November 1, 2007.10.44 Letter Agreement, dated August 24, 2007, by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit10.1 to Form 8-K (file no. 001-14901) filed on August 24, 2007.10.45 Offer Letter, dated February 14, 2005, between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.58 to Form8-K (file no. 001-14901), filed on March 4, 2005.10.46 Executive Officer Term Sheet with P. Jerome Richey incorporated by reference to Exhibit 10.12 to Form 10-K for the year ended December 31,2008 (file no. 001-14901), filed on February 17, 2009.10.47 Change in Control Agreement by and between CONSOL Energy Inc. and J. Brett Harvey, incorporated by reference to Exhibit 10.3 to Form 10-Kfor the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.48 Change in Control Agreement by and between CONSOL Energy Inc. and William J. Lyons, incorporated by reference to Exhibit 10.4 to Form10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.49 Change in Control Agreement by and between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.6 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.18710.50 Change in Control Agreement by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.7 to Form10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.51 Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Robert Pusateri, incorporated by reference toExhibit 10.8 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.52 Change in Control Severance Agreement, dated as of December 2, 2008 and amended as of February 23, 2010, between CONSOL Energy Inc.and Robert Pusateri, incorporated by reference to Exhibit 10.9 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2010, filed onMay 4, 2010.10.53 Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 toForm 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.10.54 Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by reference to Exhibit 10.7 toForm 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.10.55 Equity Incentive Plan, As Amended and Restated, effective April 28, 2009, incorporated by reference to Exhibit 10.1 to the Form 8-K (file no.001-14901) filed on May 1, 2009.10.56 Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 1, 2008.10.57 Long-Term Incentive Program (2009-2011), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter endedMarch 31, 2009, filed on April 27, 2009.10.58 Long-Term Incentive Program (2010 - 2012), incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter endedMarch 31, 2010, filed on May 4, 2010.10.59 Long-Term Incentive Program (2011 - 2013), incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter endedMarch 31, 2011, filed on May 3, 2011.10.60 Non-Employee Director Option Grant Notice, as amended, incorporated by reference to Exhibit 10.84 to the Form 8-K (file no. 001-14901) filedon October 24, 2005.10.61 Form of Non-Qualified Stock Option Award Agreement For Employees, incorporated by reference to Exhibit 10.26 to the Registration Statementon Form S-4 (file no. 333-149442) filed on February 28, 2008.10.62 Form of Non-Qualified Stock Option Award Agreement for Employees (February 17, 2009 and after), incorporated by reference to Exhibit 10.28to Form S-4 (file no. 333-157894) filed on June 26, 2009.10.63 Form of Employee Non-Qualified Performance Stock Option Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.10.64 Form of Restricted Stock Unit Award Agreement for Employees, incorporated by reference to Exhibit 10.28 to the Registration Statement on FormS-4 (file no. 333-149442) filed on February 28, 2008.10.65 Form of Restricted Stock Unit Award for Employees (February 17, 2009 and after), incorporated by reference to Exhibit 10.31 to AmendmentNo. 1 to Form S-4 (file no. 333-157894) filed on June 26, 2009.10.66 Form of Restricted Stock Unit Award Agreement for Directors, incorporated by reference to Exhibit 10.30 to the Registration Statement on FormS-4 (file no. 333-149442) filed on February 28, 2008.10.67 Form of Election and Restricted Stock Unit Award Agreement (Exchange Offer), incorporated by reference to Exhibit 99.1 to Form S-4/A (file no.333-157894) filed on June 26, 2009.10.68 Election Form to Exchange CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement),incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.10.69 Form of CONSOL Energy Inc. Restricted Stock Unit Award Agreement for Individuals Exchanging CNX Gas Performance Share Units intoCONSOL Energy Inc. Restricted Stock Units (Private Placement), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901)for the quarter ended March 31, 2009, filed on April 27, 2009.10.70 Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.60 to Form 10-K for the year ended December 31,2010 (file no. 001-14901), filed on February 10, 2011.10.71 Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarterended March 31, 2008, filed on April 30, 2008.10.72 Hypothetical Investment Election Form Relating to Directors' Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit10.53 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.73 Directors' Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q(file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.18810.74 Hypothetical Investment Election Form Relating to Directors' Deferred Fee Plan (2004 Plan), incorporated by reference to Exhibit 10.50 to Form10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.10.75 Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K (file no. 001-14901) filed onMay 8, 2006.10.76 Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan), incorporated by reference toExhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.10.77 Trust Agreement (Amended and Restated on March 20, 2008) (2004 Directors Deferred Fee Plan), incorporated by reference to Exhibit 10.4 toForm 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.10.78 Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc., incorporated reference to Exhibit 10.30 to Form 10-K for the yearended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.10.79 Amended and Restated Supplemental Retirement Plan of CONSOL Energy Inc. effective January 1, 2007, as amended and restated onSeptember 8, 2009, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on September 11, 2009.10.80 Amendment to CONSOL Energy Inc. Supplemental Retirement Plan, dated as of October 17, 2011, incorporated by reference to Exhibit 10.3 toForm 10-Q (file no. 001-14901), for the quarter ended September 30, 2011, filed on October 31, 2011.10.81 CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.23 to the CNX Gas Corporation Form 10-Kfor the year ended December 31, 2008 (file no. 001-32723), filed on February 17, 2009.10.82 Form of Award Agreements under CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.5 toAmendment No. 1 to the Form S-1 (file no. 333-127483) for CNX Gas Corporation, filed on September 29, 2005.12 Computation of Ratio of Earnings to Fixed Charges.14.1 Code of Employee Business Conduct, incorporated by reference to Exhibit 14.1 to Form 8-K (file no. 001-14901)filed on December 5, 2008.21 Subsidiaries of CONSOL Energy Inc.23.1 Consent of Ernst & Young LLP23.2 Consent of Netherland Sewell & Associates, Inc.31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of200232.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of200299 Engineers' Audit Letter101 Interactive Data File (Form 10-K for the year ended December 31, 2011 furnished in XBRL).Supplemental InformationNo annual report or proxy material has been sent to shareholders of CONSOL Energy at the time of filing of this Form 10-K. An annual report will besent to shareholders and to the commission subsequent to the filing of this Form 10-K.In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.189SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized, as of the 10th day of February, 2012. CONSOL ENERGY INC. By: /S/ J. BRETT HARVEY J. Brett Harvey Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 10th day of February, 2012, by the followingpersons on behalf of the registrant in the capacities indicated:Signature Title /S/ J. BRETT HARVEY Chairman of the Board and Chief Executive OfficerJ. Brett Harvey (Principal Executive Officer) /S/ WILLIAM J. LYONS Chief Financial Officer and Executive Vice PresidentWilliam J. Lyons (Principal Financial Officer) /S/ JOHN L. WHITMIRE Vice Chairman of the BoardJohn L. Whitmire /S/ PHILIP W. BAXTER Lead Independent DirectorPhilip W. Baxter /S/ JAMES E. ALTMEYER, SR. DirectorJames E. Altmeyer, Sr. /S/ WILLIAM E. DAVIS DirectorWilliam E. Davis /S/ RAJ K. GUPTA DirectorRaj K. Gupta /S/ PATRICIA A. HAMMICK DirectorPatricia A. Hammick /S/ DAVID C. HARDESTY, JR. DirectorDavid C. Hardesty, Jr. /S/ JOHN T. MILLS DirectorJohn T. Mills /S/ WILLIAM P. POWELL DirectorWilliam P. Powell /S/ JOSEPH T. WILLIAMS DirectorJoesph T. Williams 190SCHEDULE IICONSOL ENERGY INC. AND SUBSIDIARIESValuation and Qualifying Accounts(Dollars in thousands) Additions Deductions Balance at Release of Balance at Beginning Charged to Valuation Charged to End of Period Expense Allowance Expense of PeriodYear Ended December 31, 2011 State operating loss carry-forwards $39,744 $1,530 $(6,294) $— $34,980 Deferred deductible temporary differences 22,924 — (10,747) (6,141) 6,036 Total $62,668 $1,530 $(17,041) $(6,141) $41,016 Year Ended December 31, 2010 State operating loss carry-forwards $37,052 $3,917 $(1,225) $— $39,744 Deferred deductible temporary differences 24,571 287 (1,934) — 22,924 Total $61,623 $4,204 $(3,159) $— $62,668 Year Ended December 31, 2009 State operating loss carry-forwards $34,714 $2,640 $(302) $— $37,052 Deferred deductible temporary differences 26,184 949 (2,562) — 24,571 Total $60,898 $3,589 $(2,864) $— $61,623191Exhibit 12Computation of Ratio of Earnings to Fixed Charges(In Thousands) Twelve Months Ended December 31, 2011 2010 2009 2008 2007Earnings: Income from continuing operations before income taxes $787,953 $467,913 $788,345 $725,595 $428,957 Fixed charges, as shown below 301,178 249,804 69,277 69,402 61,336 Equity in income of investees (24,663) (21,428) (15,707) (11,140) (6,551) Noncontrolling Interest–Gas — (11,845) (27,425) (43,191) (25,038)Adjusted Earnings (Loss) $1,064,468 $684,444 $814,490 $740,666 $458,704 Fixed charges: Interest on indebtedness, expensed or capitalized $263,891 $218,425 $43,290 $48,345 $45,414 Interest within rent expense 37,287 31,379 25,987 21,057 15,922Total Fixed Charges $301,178 $249,804 $69,277 $69,402 $61,336 Ratio of Earnings to Fixed Charges 3.53 2.74 11.76 10.67 7.48Exhibit 21CONSOL Energy Inc.SUBSIDIARIESAs of January 31, 2012(In alphabetical order)AMVEST Coal & Rail, LLC. (a Virginia limited liability company) Eighty-Four Mining Company (a Pennsylvania corporation)AMVEST Coal Sales, Inc. (a Virginia corporation) Fairmont Supply Company (a Delaware corporation)AMVEST Corporation (a Virginia corporation) Fairmont Supply Oil and Gas LLC (formerly North PennAMVEST Gas Resources, Inc. (a Virginia corporation) Pipe & Supply, LLC) (a Pennsylvania limited liability company)AMVEST Mineral Services, Inc. (a Virginia corporation) Fola Coal Company, LLC. d/b/a Powellton Coal Company (a WestAMVEST Minerals Company, LLC. (a Virginia limited liability Virginia limited liability company)company) Glamorgan Coal Company, LLC. (a Virginia limited liabilityAMVEST Oil & Gas, Inc. (a Virginia corporation) company)AMVEST West Virginia Coal, LLC. (a West Virginia limited Helvetia Coal Company (a Pennsylvania corporation)liability company) Island Creek Coal Company (a Delaware corporation)Braxton-Clay Land & Mineral, Inc. (a West Virginia corporation) Keystone Coal Mining Corporation (a Pennsylvania corporation)Cardinal States Gathering Company (a Virginia general partnership) Knox Energy, LLC. (a Tennessee limited liability company)Central Ohio Coal Company (an Ohio corporation) Laurel Run Mining Company (a Virginia corporation)CNX Funding Corporation (a Delaware corporation) Leatherwood, Inc. (a Pennsylvania corporation)CNX Gas Company LLC (a Virginia limited liability company) Little Eagle Coal Company, L.L.C. (a West Virginia limited liabilityCNX Gas Corporation (a Delaware corporation) company)CNX Land Resources Inc. (a Delaware corporation) McElroy Coal Company (a Delaware corporation)CNX Marine Terminals Inc. (formerly Consolidation MOB Corporation (a Pennsylvania corporation) Coal Sales Company) (a Delaware corporation) Mon River Towing, Inc. (a Pennsylvania corporation)CNX Water Assets LLC (formerly CONSOL of WV LLC) (a West Mon-View, LLC (a West Virginia limited liability company)Virginia limited liability company) MTB, Inc. (a Delaware corporation)Coalfield Pipeline Company (a Tennessee corporation) Nicholas-Clay Land & Mineral, Inc. (a Virginia corporation)Conrhein Coal Company (a Pennsylvania general partnership) Peters Creek Mineral Services, Inc. (a Virginia corporation)CONSOL Energy Canada Ltd. (a Canadian corporation) Piping and Equipment, Inc. (a Florida corporation)CONSOL Energy Holdings LLC VI (a Delaware limited liability Reserve Coal Properties Company (a Delaware corporation)company) Rochester & Pittsburgh Coal Company (a Pennsylvania corporation)CONSOL Energy Sales Company (formerly CONSOL Sales Southern Ohio Coal Company (a West Virginia corporation) Company) (a Delaware corporation) TEAGLE Company, LLC. (a Virginia limited liability company)CONSOL Financial Inc. (a Delaware corporation) TECPART Corporation (a Delaware corporation)CONSOL of Canada Inc. (a Delaware corporation) Terra Firma Company (a West Virginia corporation)CONSOL of Central Pennsylvania LLC (a Pennsylvania Terry Eagle Coal Company, L.L.C. (a West Virginia limited liabilityCONSOL of Kentucky Inc. (a Delaware corporation) company)CONSOL of Ohio LLC (an Ohio limited liability company) Terry Eagle Limited Partnership (a West Virginia limitedCONSOL of Wyoming LLC (a Delaware limited liability company) partnership)Consol Pennsylvania Coal Company LLC (formerly Consol Twin Rivers Towing Company (a Delaware corporation) Pennsylvania Coal Company) (a Delaware limited liability Vaughan Railroad Company (a West Virginia corporation)company) Windsor Coal Company (a West Virginia corporation)Consolidation Coal Company (a Delaware corporation) Wolfpen Knob Development Company (a Virginia corporation)Exhibit 23.1Consent of Independent Registered Public Accounting FirmWe consent to the incorporation by reference in the Registration Statement on Form S-3 (File No. 333-172695) of CONSOL Energy Inc. andSubsidiaries and in the related Prospectuses, and the Registration Statement on Form S-4 (File No. 333-176045) of CONSOL Energy Inc. and Subsidiariesand in the related Prospectuses, and the Registration Statements on Form S-8 (File No. 333-167892, File No. 333-126057, File No. 333-126056, File No. 333-113973, File No. 333-87545, File No. 333-160273, File No. 333-177023) of CONSOL Energy Inc. and Subsidiaries of our reports dated February 10, 2012,with respect to the consolidated financial statements and schedule of CONSOL Energy Inc. and Subsidiaries, and the effectiveness of internal control overfinancial reporting of CONSOL Energy Inc. and Subsidiaries included in this Annual Report (form 10-K) for the year ended December 31, 2011./s/ Ernst & Young, LLPPittsburgh, PennsylvaniaFebruary 10, 2012Exhibit 23.2Consent of Independent Petroleum Engineers and GeologistsAs independent petroleum engineers, we hereby consent to (a) the use of our audit letter relating to the proved reserves of gas and oil (including coalbedmethane) of CONSOL Energy, Inc. as of December 31, 2011 (b) the references to us as experts in CONSOL Energy Inc.'s Annual Report on Form 10-K forthe year ended December 31, 2011 and (c) the incorporation by reference of our name and our audit letter into CONSOL Energy Inc's Registration Statementson Form S-8 (File No. 333-167892, File No. 333-160273, File No. 333-126057, File No. 333-126056, File No. 333-113973, File No. 333-87545 and 333-177023), Form S-4 (File No. 333-176045) and Form S-3 (File No. 333-172695), that incorporate by reference such Form 10-K.We further wish to advise that we are not employed on a contingent basis and that at the time of the preparation of our report, as well as at present,neither Netherland, Sewell & Associates, Inc. nor any of its employees had, or now has, a substantial interest in CONSOL Energy Inc. or any of itssubsidiaries, as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.NETHERLAND, SEWELL & ASSOCIATES,INC. By:/s/ DANNY D. SIMMONS, P.E. Danny D. Simmons, P.E. President and Chief Operating OfficerHouston, TexasFebruary 10, 2012Exhibit 31.1CERTIFICATIONSI, J. Brett Harvey, certify that:1.I have reviewed this annual report on Form 10-K of CONSOL Energy Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers within those entities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. Date:February 10, 2012 /s/ J. Brett Harvey J. Brett Harvey Chairman of the Board and Chief Executive Officer (Principal Executive Officer) Exhibit 31.2CERTIFICATIONS I, William J. Lyons, certify that:1.I have reviewed this annual report on Form 10-K of CONSOL Energy Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers within those entities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information;(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internalcontrol over financial reporting. Date:February 10, 2012 /s/ William J. Lyons William J. Lyons Chief Financial Officer and Executive Vice President(Principal Financial and Accounting Officer) Exhibit 10.32EXECUTION VERSIONAMENDMENT NO. 1 TOCREDIT AGREEMENTAMENDMENT NO. 1, dated as of December 14, 2011 (this “Amendment”), to the Amended and Restated Credit Agreement,dated as of April 12, 2011 (the “Credit Agreement”), by and among CNX Gas Corporation (the “Borrower”), the lenders and agentsparty thereto and PNC Bank, National Association, as administrative agent (the “Administrative Agent”). Capitalized terms used but notdefined herein shall have the meanings given them in the Credit Agreement.WITNESSETHWHEREAS, the Borrower has requested the amendments to the Credit Agreement set forth herein.NOW, THEREFORE, the parties hereto, in consideration of the mutual covenants and agreements herein contained andintending to be legally bound hereby, covenant and agree as follows:1.Amendments.(a)Investments. Section 8.2.4 of the Agreement is hereby amended by (i) deleting the word “and” at the end ofclause (h) thereof, (ii) deleting the period at the end of clause (i) thereof and (iii) adding the following clauses (j) and (k) at theend of such section:“(j) Investments in CONSOL in the form of loans or advances in an aggregate amount not to exceed$600,000,000; provided that at the time of any such Investments, (x) no Event of Default or Potential Default shallexist or shall result from such Investment, (y) the Leverage Ratio is 3.0 to 1.0 or less, and (z) the Revolving FacilityUsage does not exceed 75% of the lesser of the Borrowing Base and the Revolving Credit Commitment; provided,further, that all payments under any Guaranty permitted by Section 8.2.3(a) and all payments pursuant to Section8.2.5(b) shall reduce the amount of Investments permitted by this Section 8.2.4(j); and(k) Investments made in the form of (i) assets constituting Significant Gathering Systems and (ii) cash in anyJoint Venture in which the Borrower or any Loan Party participates for the development or operation of the SignificantGathering Systems, which cash Investments are made in the ordinary course of business of such Joint Venture.”(b)Dividends. Clause (b) of Section 8.2.5(b) is hereby amended and restated as follows:“(b) dividends payable by the Borrower on common stock of the Borrower and purchases or redemptions bythe Borrower of its common stock in an aggregate amount after the Closing Date not to exceed $600,000,000; providedthat at the time of any such dividend, purchase or redemption and after giving1effect thereto, (x) no Event of Default or Potential Default shall exist or shall result from such dividend, purchase orredemption, (y) the Leverage Ratio is 3.0 to 1.0 or less, and (z) the Revolving Facility Usage does not exceed 75% ofthe lesser of the Borrowing Base and the Revolving Credit Commitment; provided, further, that all payments underany Guaranty permitted by Section 8.2.3(a) and all Investments pursuant to Section 8.2.4(j) shall reduce the amount ofdividends, purchases and redemptions permitted by this Section 8.2.5(b); and”.(c)Dispositions of Assets. Section 8.2.7 of the Agreement is hereby amended by (i) deleting the word“or” at the end of clause (g) thereof, (ii) deleting the period and adding “; or” at the end of clause (h) thereof and (iii)adding the following clause (i) at the end of such section:“(i) Investments made pursuant to Section 8.2.4.”2.Condition Precedent. This Amendment shall be effective upon completion of each of the following conditions to thesatisfaction of the Administrative Agent(a)Execution and Delivery of Amendment. The Borrower shall have executed this Amendment, and theAdministrative Agent shall have received consent from the Required Lenders to execute and shall have executed thisAmendment.(b)Fees. The Borrower shall have paid all reasonable legal fees and expenses of counsel to the AdministrativeAgent for the preparation and execution of this Amendment.(c)Representations and Warranties. After giving effect to this Amendment, the representations and warrantiesin the Loan Documents are true and correct in all material respects (except where such representations and warrantiesexpressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in allmaterial respects as of such earlier date).(d)No Default. After giving effect to this Amendment, no Default or Event of Default has occurred and iscontinuing.3.Full Force and Effect. Except as expressly modified by this Amendment, all of the terms, conditions,representations, warranties and covenants contained in the Loan Documents shall continue in full force and effect, including withoutlimitation, all liens and security interests granted pursuant to the Loan Documents. This Amendment shall constitute a Loan Documentfor purposes of the Credit Agreement on and after the effectiveness of this Amendment and all references to the Credit Agreement inany Loan Document and all references in the Credit Agreement to “this Agreement,” “hereunder,” “hereof” or words of like importreferring to the Credit Agreement, shall, unless expressly provided otherwise, shall mean and be a reference to the Credit Agreement,as amended by this Amendment.4.Counterparts. This Amendment may be executed by different parties hereto in any number of separate counterparts,each of which, when so executed and delivered shall be an original and all such counterparts shall together constitute one and the sameinstrument.5.Severability. If any term of this Amendment or any application thereof shall be held to be2invalid, illegal or unenforceable, the validity of other terms of this Amendment or any other application of such term shall in no way beaffected thereby.6.Entire Agreement. This Amendment sets forth the entire agreement and understanding of the parties with respect tothe amendments to the Credit Agreement contemplated hereby and supersedes all prior understandings and agreements, whetherwritten or oral, between the parties hereto relating to such amendments. No representation, promise, inducement or statement ofintention has been made by any party that is not embodied in this Amendment, and no party shall be bound by or liable for any allegedrepresentation, promise, inducement or statement of intention not set forth herein.7.Governing Law. This Agreement shall be deemed to be a contract under the Laws of the State of New York withoutregard to its conflict of laws principles.[SIGNATURES APPEAR ON FOLLOWING PAGES]3[SIGNATURE PAGE TO AMENDMENT NO. 1TO CREDIT AGREEMENT]IN WITNESS WHEREOF, the parties hereto, by their officers thereunto duly authorized, have executed this Amendment asof the day and year first above written. CNX GAS CORPORATION By:/s/ John M. Reilly Name:John M. Reilly Title:Vice President & Treasurer PNC BANK, NATIONAL ASSOCIATION By:/s/ Richard C. Munsick Name:Richard C. Munsick Title:Senior Vice President BANK OF AMERICA, N.A., as a Lender By:/s/ Adam H. Fey Name:Adam H. Fey Title:Director BANK OF MONTREAL, CHICAGO BRANCH By:/s/ Yaco Uba Kane Name:Yaco Uba Kane Title:Vice President BOKF, NA dba Bank of Oklahoma, as a Lender By:/s/ Jason B. Webb Name:Jason B. Webb Title:Vice President Branch Banking and Trust Company, as a Lender By:/s/ Ryan K. Michael Name:Ryan K. Michael Title:Senior Vice President 4 Capital One, National Association, as a Lender By:/s/ Nancy M. Mak Name:Nancy M. Mak Title:Vice President CIBC Inc., as a Lender By:/s/ Trudy Nelson Name:Trudy Nelson Title:Authorized Signatory By:/s/ Richard Antl Name:Richard Antl Title:Authorized Signatory COMERICA BANK, as a Lender By:/s/ John S. Lesikar Name:John S. Lesikar Title:Assistant Vice President COMMONWEALTH BANK OF AUSTRALIA, as a Lender By:/s/ Greg A. Calone Name:Greg A. Calone Title:Head of Natural Resources - Americas COMPASS BANK, as a Lender By:/s/ Trey Lewis Name:Trey Lewis Title:Assistant Vice President Credit Agricole Corporate and Investment Bank, as a Lender By:/s/ Matthias Guillet Name:Matthias Guillet Title:Director By:/s/ Melvin Smith Name:Melvin Smith Title:Vice President 5 Fifth Third Bank, as a Lender By:/s/ Jim Janovsky Name:Jim Janovsky Title:Vice President First National Bank of Pennsylvania, as a Lender By:/s/ Anthony M. Marfisi Name:Anthony M. Marfisi Title:Senior Vice President and Regional Manager GOLDMAN SACHS BANK USA, as a Lender By:/s/ Ashwin Ramakrishna Name:Ashwin Ramakrishna Title:Authorized Signatory ING CAPITAL LLC, as a Lender By:/s/ Charles Hall Name:Charles Hall Title:Managing Director JPMorgan Chase Bank, N.A., as a Lender By:/s/ Jo Linda Papadakis Name:Jo Linda Papadakis Title:Authorized Officer NATIXIS, as a Lender By:/s/ Liana Tchernysheva Name:Liana Tchernysheva Title:Managing Director By:/s/ Donovan C. Broussard Name:Donovan C. Broussard Title:Managing Director PNC BANK, NATIONAL ASSOCIATION, as a LenderIndividually and as Administrative Agent By:/s/ Richard C. Munsick Name:Richard C. Munsick Title:Senior Vice President 6 Fifth Third Bank, as a Lender By:/s/ Jim Janovsky Name:Jim Janovsky Title:Vice President First National Bank of Pennsylvania, as a Lender By:/s/ Anthony M. Marfisi Name:Anthony M. Marfisi Title:Senior Vice President and Regional Manager GOLDMAN SACHS BANK USA, as a Lender By:/s/ Ashwin Ramakrishna Name:Ashwin Ramakrishna Title:Authorized Signatory ING CAPITAL LLC, as a Lender By:/s/ Charles Hall Name:Charles Hall Title:Managing Director JPMorgan Chase Bank, N.A., as a Lender By:/s/ Jo Linda Papadakis Name:Jo Linda Papadakis Title:Authorized Officer NATIXIS, as a Lender By:/s/ Liana Tchernysheva Name:Liana Tchernysheva Title:Managing Director By:/s/ Donovan C. Broussard Name:Donovan C. Broussard Title:Managing Director PNC BANK, NATIONAL ASSOCIATION, as a LenderIndividually and as Administrative Agent By:/s/ Richard C. Munsick Name:Richard C. Munsick Title:Senior Vice President7 Soverign Bank, as a Lender By:/s/ Daniela Hofer-Gautschi Name:Daniela Hofer-Gautschi Title:Vice President TD Bank, N.A., as a Lender By:/s/ Marla Willner Name:Marla Willner Title:Senior Vice President The Bank of Nova Scotia, as a Lender By:/s/ Frank Sandler Name:Frank Sandler Title:Managing Director The Bank of Tokyo-Mitsubishi UFJ, Ltd., as a Lender By:/s/ Andrew Oram Name:Andrew Oram Title:Managing Director The Huntington National Bank, as a Lender By:/s/ Chad A. Lowe Name:Chad A. Lowe Title:Vice President THE ROYAL BANK OF SCOTLAND plc, as a Lender By:/s/ Sanjay Remond Name:Sanjay Remond Title:Authorised Signatory TriState Capital Bank, as a Lender By:/s/ Paul J. Oris Name:Paul J. Oris Title:Senior Vice President8 Union Bank, as a Lender By:/s/ Bradley Kraus Name:Bradley Kraus Title:Investment Banking Officer U.S. Bank National Association, as a Lender By:/s/ Tyler Fauerback Name:Tyler Fauerbach Title:Vice President Wells Fargo, N.A., as a Lender By:/s/ Joseph Rottinghaus Name:Joseph Rottinghaus Title:Assistant Vice President9Exhibit 32.1CERTIFICATIONPursuant to Section 906 of the Sarbanes-Oxley Act of 2002,18 U.S.C. Section 1350I, J. Brett Harvey, President and Chief Executive Officer (principal executive officer) of CONSOL Energy Inc. (the “Registrant”), certify that to myknowledge, based upon a review of the Annual Report on Form 10-K for the period ended December 31, 2011, of the Registrant (the “Report”): (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theRegistrant. Date:February 10, 2012 /s/ J. Brett Harvey J. Brett Harvey Chairman of the Board and Chief Executive Officer Exhibit 32.2CERTIFICATIONPursuant to Section 906 of the Sarbanes-Oxley Act of 2002,18 U.S.C. Section 1350I, William J. Lyons, Chief Financial Officer (principal financial officer) of CONSOL Energy Inc. (the “Registrant”), certify that to my knowledge,based upon a review of the Annual Report on Form 10-K for the period ended December 31, 2011, of the Registrant (the “Report”): (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theRegistrant.Date:February 10, 2012 /s/ William J. Lyons William J. Lyons Chief Financial Officer and Executive Vice President Exhibit 95Mine Safety and Health Administration Safety DataWe believe that CONSOL Energy is one of the safest mining companies in the world. The Company has in place health and safety programs that includeextensive employee training, accident prevention, workplace inspection, emergency response, accident investigation, regulatory compliance and programauditing. The objectives of our health and safety programs are to eliminate workplace incidents, comply with all mining-related regulations and providesupport for both regulators and the industry to improve mine safety.The operation of our mines is subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and HealthAct of 1977 (Mine Act). MSHA inspects our mines on a regular basis and issues various citations, orders and violations when it believes a violation hasoccurred under the Mine Act. We present information below regarding certain mining safety and health violations, orders and citations, issued by MSHA andrelated assessments and legal actions and mine-related fatalities with respect to our coal mining operations. In evaluating this information, consideration shouldbe given to factors such as: (i) the number of violations, orders and citations will vary depending on the size of the coal mine, (ii) the number of violations,orders and citations issued will vary from inspector to inspector and mine to mine, and (iii) violations, orders and citations can be contested and appealed,and in that process, are often reduced in severity and amount, and are sometimes dismissed.The table below sets forth for the twelve months ended December 31, 2011 for each coal mine of CONSOL Energy and its subsidiaries, the total number of: (i) violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safetyor health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) orders issued under section 104(b) of the MineAct; (iii) citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of theMine Act; (iv) flagrant violations under section 110(b)(2) of the Mine Act; (v) imminent danger orders issued under section 107(a) of the Mine Act; (vi)proposed assessments from MHSA (regardless of whether CONSOL Energy has challenged or appealed the assessment); (vii) mining-related fatalities; (viii)notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantiallycontributed to the cause and effect of coal or other mine health or safety hazards under section 104(e) of the Mine Act; (ix) notices from MSHA regarding thepotential to have a pattern of violations as referenced in (viii) above; and (x) pending legal actions before the Federal Mine Safety and Health ReviewCommission (as of December 31, 2011) involving such coal or other mine, as well as the aggregate number of legal actions instituted and the aggregate numberof legal actions resolved during the reporting period.1 Received Notice Received of Legal Total Dollar Total Notice of Potential Actions Section Value of Number Pattern of to have Pending Legal Legal Section 104(d) MSHA of Violations Pattern as of Actions ActionsMine or Operating 104 Section Citations Section Section Assessments Mining Under Under Last Initiated ResolvedName/MSHA S&S 104(b) and 110(b)(2) 107(a) Proposed (in Related Section Section Day of During DuringIdentification Number Citations Orders Orders Violations Orders thousands) Fatalities 104(e) 104(e) Period (1) Period PeriodActive Operations Bailey 36-07230 49 — — — — $230 — No No 10 21 28Blacksville 2 46-01968 198 — 6 — — $930 — No No 16 21 28Bronzite II (MT-41) 46-09307 27 — — — — $40 — No No 5 7 —Bronzite III (Jacobs) 46-05978 36 — — — — $33 — No No — 5 4Buchanan 44-04856 175 — — — — $1,172 — No No 30 17 18Central Repair Shop 46-03240 — — — — — $— — No No — — —Enlow Fork 36-07416 40 — — — — $110 — No No 6 14 25Fola Surface 46-08377 2 — — — — $5 — No No 2 6 8Ireland DockLoadout 46-01438 — — — — — $1 — No No 4 1 —Keystone CleaningPlant 36-08540 1 — — — — $5 — No No — — —Loveridge 46-01433 282 3 11 — — $1,304 — No No 11 17 31McElroy 46-01437 301 — 9 — 1 $1,133 — No No 17 24 34Miller Creek PP #1 46-05890 35 — — — — $13 — No No 4 3 2Minway Surface 46-06089 6 — — — — $6 — No No 1 1 —Peach Orchard PrepPlant 46-08376 2 — — — — $1 — No No — — —Robinson Run 46-01318 134 — 3 — — $887 — No No 18 25 27Rock Lick 46-09171 35 — 1 — — $112 — No No 6 18 5Shoemaker 46-01436 245 — 5 — — $649 1 No No 9 17 24Wiley Creek (MT-13/500) 46-09185 4 — — — — $4 — No No — — 2WileySurface(MT34/PegFork) 46-09035 9 — — — 1 $6 — No No — — — Inactive Operations Alma No. 1 Mine 46-09277 1 — — — — $— — No No — — —Amonate 46-05449 — — — — — $— — No No — — —Big Branch#1Belt/Spruce Creek 46-09177 3 — — — — $1 — No No — — 6Big Fork 44-06859 — — — — — $6 — No No — — —Elk Creek Prep Plant 46-02444 — — — — — $— — No No — — —Emery 42-00079 4 — — — — $108 — No No 8 9 15Impoundment 14-N 36-08094 — — — — — $— — No No — — 12Jones Fork E-3(Sold) 15-18589 — — — — — $3 — No No 1 1 5Jones Fork PrepPlant(Sold) 15-17021 — — — — — $— — No No — — —Laurel Fork 46-09084 — — — — — $— — No No — — —Lick Branch 46-08676 17 — — — — $32 — No No 3 4 1Little Eagle Mine #1 46-08560 — — — — — $— — No No — — —Meigs #31 Mine 33-01172 — — — — — $— — No No — — —Miles Branch 44-03932 — — — — — $— — No No — — 2Mine 84 36-00958 2 — — — — $19 — No No — 3 8Muskingum 33-00989 — — — — — $— — No No — — —Powellton/BridgeFork 46-08889 — — — — — $— — No No — — —Reclamation #061 33-00962 — — — — — $— — No No — — —Rend Lake 11-00601 — — — — — $— — No No — — —Robena Prep 36-04175 — — — — — $— — No No — — —Terry Eagle PP #1 46-02295 — — — — — $— — No No — — —Wiley (MT-11) 46-09138 — — — — — $— — No No — — —Wiley Area 80 15-18477 — — — — — $— — No No — — —Winoc Prep Plant 46-08172 — — — — — $— — No No — — — 1,608 3 35 — 2 $6,810 1 151 214 2743(1) See table below for additional detail regarding Legal Actions Pending as of December 31, 2011. With respect to Contests of Proposed Penalties,we have included the number of dockets (as opposed to citations) when counting the number of Legal Actions Pending as of December 31, 2011.Mine or Operating Name/MSHA IdentificationNumber Contests ofCitations,Orders(as of 12.31.11)(a) Contests of Proposed Penalties(as of 12.31.11)(b) Complaints forCompensation(as of 12.31.11)(c) Complaints ofDischarge,Discriminationor Interference(as of 12.31.11)(d) Applicationsfor TemporaryRelief(as of 12.31.11)(e) Appeals ofJudges'Decisions orOrder(as of 12.31.11)(f) Dockets Citations Active Operations Bailey 36-07230 — 7 15 — 3 — —Blacksville 2 46-01968 — 16 143 — — — —Bronzite II (MT‑41) 46-09307 — 5 11 — — — —Bronzite III (Jacobs) 46-05978 — 3 11 — — — —Buchanan 44-04856 — 29 444 — 1 — —Central Repair Shop 46-03240 — — — — — — —Enlow Fork 36-07416 — 6 38 — — — —Fola Surface 46-08377 — 2 2 — — — —Ireland Dock Loadout 46-01438 — 4 5 — — — —Keystone Cleaning Plant 36-08540 — — — — — — —Loveridge 46-01433 — 11 64 — — — —McElroy 46-01437 — 17 207 — — — —Miller Creek PP #1 46-05890 — 2 5 — 2 — —Minway Surface 46-06089 — 1 2 — — — —Peach Orchard Prep Plant 46-08376 — — — — — — —Robinson Run 46-01318 — 15 159 — 3 — 1Rock Lick 46-09171 — 6 14 — — — —Shoemaker 46-01436 — 9 33 — — — —Wiley Creek (MT‑13/500) 46-09185 — — — — — — —Wiley Surface(MT34/Peg Fork) 46-09035 — — — — — — — Inactive Operations Alma No. 1 Mine 46-09277 — — — — — — —Amonate 46-05449 — — — — — — —4Big Branch #1Belt/Spruce Creek 46-09177 — — — — — — —Big Fork 44-06859 — — — — — — —Elk Creek Prep Plant 46-02444 — — — — — — —Emery 42-00079 — — — — — — —Impoundment 14‑N 36-08094 — — — — — — —Jones Fork E‑3(Sold) 15-18589 — — — — — — —Jones Fork Prep Plant(Sold) 15-17021 — — — — — — —Laurel Fork 46-09084 — — — — — — —Lick Branch 46-08676 — — — — — — —Little Eagle Mine #1 46-08560 — — — — — — —Meigs #31 Mine 33-01172 — — — — — — —Miles Branch 44-03932 — — — — — — —Mine 84 36-00958 — — — — — — —Muskingum 33-00989 — — — — — — —Powellton/Bridge Fork 46-08889 — — — — — — —Reclamation #061 33-00962 — — — — — — —Rend Lake 11-00601 — — — — — — —Robena Prep 36-04175 — — — — — — —Terry Eagle PP #1 46-02295 — — — — — — —Wiley (MT‑11) 46-09138 — — — — — — —Wiley Area 80 15-18477 — — — — — — —Winoc Prep Plant 46-08172 — — — — — — — — 133 1,153 — 9 — 15(a) Represents (if any) contests of citations and orders, which typically are filed prior to an operator's receipt of a proposed penalty assessment from MSHA or relate to orders forwhich penalties are not assessed (such as imminent danger orders under Section 107 of the Mine Act). This category includes: (i) contests of citations or orders issued undersection 104 of the Mine Act, (ii) contests of imminent danger withdrawal orders under section 107 of the Mine Act, and (iii) Emergency response plan dispute proceedings (asrequired under the Mine Improvement and New Emergency Response Act of 2006, Pub. L. No. 109-236, 120 Stat. 493).(b) Represents (if any) contests of proposed penalties, which are administrative proceedings before the Federal Mine Safety and Health Review Commission (“FMSHRC”)challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order. This column includes four actions involving civil penalties against agents of theoperator that have been contested.(c) Represents (if any) complaints for compensation, which are cases under section 111 of the Mine Act that may be filed with the FMSHRC by miners idled by a closure orderissued by MSHA who are entitled to compensation.(d) Represents (if any) complaints of discharge, discrimination or interference under section 105 of the Mine Act, which cover: (i) discrimination proceedings involving a miner'sallegation that he or she has suffered adverse employment action because he or she engaged in activity protected under the Mine Act, such as making a safety complaint, and (ii)temporary reinstatement proceedings involving cases in which a miner has filed a complaint with MSHA stating that he or she has suffered such discrimination and has lost his orher position.(e) Represents (if any) applications for temporary relief, which are applications under section 105(b)(2) of the Mine Act for temporary relief from any modification or terminationof any order or from any order issued under section 104 of the Mine Act (other than citations issued under section 104(a) or (f) of the Mine Act).(f) Represents (if any) appeals of judges' decisions or orders to the FMSHRC, including petitions for discretionary review and review by the FMSHRC on its own motion.6Exhibit 99January 31, 2012Mr. Chris MillerCONSOL Energy Inc.1000 CONSOL Energy DriveCanonsburg, Pennsylvania 15317Dear Mr. Miller:In accordance with your request, we have audited the estimates prepared by CONSOL Energy Inc. (CONSOL), as of December 31, 2011, of the provedreserves and future revenue to the CONSOL interest in certain oil and gas properties located in the United States. It is our understanding that the provedreserves estimates shown herein constitute all of the proved reserves owned by CONSOL. We have examined the estimates with respect to reserves quantities,reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S.Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance withthe definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting StandardsCodification Topic 932, Extractive Activities–Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared forCONSOL's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriatefor such purpose.The following table sets forth CONSOL's estimates of the net reserves and future net revenue, as of December 31, 2011, for the audited properties: Net Reserves Future Net Revenue (M$) Oil Gas Present WorthCategory (MBBL) (MMCF) Total at 10%Proved Developed Producing 1,579.2 2,017,020.6 4,889,994.6 2,228,780.8Proved Developed Non-Producing — 109,309.0 313,862.4 142,341.7Proved Undeveloped — 1,344,222.3 2,663,075.8 490,185.7Total Proved 1,579.2 3,470,552.0 7,866,934.0 2,861,308.5Totals may not add because of rounding.The oil reserves shown include crude oil, condensate, and natural gas liquids (NGL). Oil volumes are expressed in thousands of barrels (MBBL); a barrel isequivalent to 42 Unites States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. The tablefollowing this letter sets forth CONSOL's estimates of net reserves and future revenue by reserves category.When compared on an area-by-area basis, some of the estimates of CONSOL are greater and some are less than the estimates of Netherland, Sewell &Associates, Inc. (NSAI). However, in our opinion the estimates of CONSOL's proved reserves and future revenue shown herein are, in the aggregate,reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Informationpromulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance thresholdset forth in the SPE Standards. We are satisfied with the methods and procedures used by CONSOL in preparing the December 31, 2011, estimates ofreserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as preparedby CONSOL.The estimates shown herein are for proved reserves. CONSOL's estimates do not include probable or possible reserves that may exist for these properties, nordo they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveysthe relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenueincluded herein have not been adjusted for risk.Prices used by CONSOL are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period Januarythrough December 2011. For oil volumes, the average West Texas Intermediate (Cushing) cash/spot price of $96.19 per barrel is adjusted by lease for quality,transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $4.118 per MMBTU is adjusted by lease for energycontent, transportation fees, and regional price differentials. All prices are held constant through the lives of the properties. The average unadjusted productprices weighted by production over the remaining lives of the properties are $90.49 per barrel of oil and $4.22 per MCF of gas.Operating costs used by CONSOL are based on historical operating expense records. These costs include the per-well overhead expenses allowed under jointoperating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overheadexpenses of CONSOL are included to the extent that they are covered under joint operating agreements for the operated properties. Capital costs used byCONSOL are based on authorizations for expenditure and actual costs from recent activity. Capital Capital costs are included as required for workovers, newdevelopment wells, and production equipment. Abandonment costs used are CONSOL's estimates of the costs to abandon the wells and production facilities;these estimates do not include any salvage value for the lease and well equipment. Operating costs are held constant through the lives of the properties, andcapital costs and abandonment costs are held constant to the date of expenditures.The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which,by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves arethose additional reserves which are suquentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result ofmarket conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussedherein, estimates of CONSOL and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent withcurrent development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place thatwould impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. Ifthe reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmentalpolicies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may varyfrom assumptions made while preparing these estimates.It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily ofsubstantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy andcompleteness of information and data furnished by CONSOL with respect to ownership interests, oil and gas production, well test data, historical costs ofoperation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if inthe course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did notrely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Ouraudit did not include a review of CONSOL's overall reserves management processes and practices.We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, thatwe considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertaintiesinherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.Supporting data documenting this audit, along with data provided by CONSOL, are on file in our office. The technical persons responsible for conductingthis audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independentpetroleum engineers, geologists, geophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-002699 By:/s/ C.H. (Scott) Rees III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer By:/s/ Richard B. Talley, Jr. By:/s/ David E. Nice Richard B. Talley, Jr., P.E. 102425 David E. Nice, P.G. 346 Vice President Vice President Date Signed: January 31, 2012 Date Signed: January 31, 2012 RBT:DEG SUMMARY OF NET RESERVES AND FUTURE REVENUECONSOL ENERGY INC. INTERESTAS OF DECEMBER 31, 2011 Investment Net Reserves Future Operating Production Ad Valorem Including Future Net Revenue (M$) Oil Gas Gross Revenue Expense Tax Tax Abandonment DiscountedCategory (MBBL) (MMCF) (M$) (M$) (M$) (M$) (M$) Total At 10%Proved Developed Producing 1,579.2 2,017,020.6 8,432,550.0 3,075,809.5 240,241.5 73,429.9 265,226.2 4,777,841.5 2,112,065.0Gas Contract Revenue — — 184,724.9 72,571.8 — — — 112,153.1 116,715.8Total Proved Developed Producing 1,579.2 2,017,020.6 8,617,274.9 3,148,381.3 240,241.5 73,429.9 265,226.2 4,889,994.6 2,228,780.8 Proved Developed Non-Producing — 109,309.0 468,840.1 119,596.5 9,549.8 2,746.6 23,084.8 313,862.4 142,341.7 Proved Undeveloped — 1,344,222.3 5,718,283.5 1,519,013.1 119,367.2 30,309.4 1,386,518.6 2,663,075.8 490,185.7 Total Proved 1,579.2 3,470,552.0 14,804,399.0 4,786,991.0 369,158.5 106,485.9 1,674,829.3 7,866,934.0 2,861,308.5Totals may not add because of rounding.

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