CONSOL Energy
Annual Report 2013

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, 2013ORoTRANSITION 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, 2013, 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 $3,294,530,080.The number of shares outstanding of the registrant's common stock as of January 20, 2014 is 229,162,591 shares.DOCUMENTS INCORPORATED BY REFERENCE:Portions of CONSOL Energy's Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2014, are incorporated by reference in Items 10, 11, 12, 13 and14 of Part III. TABLE OF CONTENTS PagePART I ITEM 1.Business5ITEM 1A.Risk Factors29ITEM 1B.Unresolved Staff Comments44ITEM 2.Properties44ITEM 3.Legal Proceedings44ITEM 4.Mine Safety and Health Administration Safety Data44 PART II ITEM 5.Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities45ITEM 6.Selected Financial Data47ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of Operations49ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk104ITEM 8.Financial Statements and Supplementary Data106ITEM 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 Schedules183SIGNATURES1912GLOSSARY OF CERTAIN OIL AND GAS MEASUREMENT TERMSThe following are abbreviations of certain measurement terms commonly used in the oil and gas industry and included within this Form 10-K:Bbl - One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.Bcf - One billion cubic feet of natural gas.Bcfe - One billion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.Btu - One British thermal unit.Mbbls - One thousand barrels of oil or other liquid hydrocarbons.Mcf - One thousand cubic feet of natural gas.Mcfe - One thousand cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.MMbtu - One million British Thermal units.MMcfe - One million cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.NGL - Natural gas liquids.Tcfe - One trillion cubic feet of natural gas equivalents, with one barrel of oil being equivalent to 6,000 cubic feet of gas.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;•an extended decline in demand for or prices we receive for our natural gas and coal affecting our operating results and cash flows;•our customers extending existing contracts or entering into new long-term contracts for coal;•our reliance on major customers;•our inability to collect payments from customers if their creditworthiness declines;•the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas and coal to market;•a loss of our competitive position because of the competitive nature of the natural gas and coal industries, or a loss of our competitive positionbecause of overcapacity in these industries impairing our profitability;•coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;•the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for natural gas and coal;•foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;•the risks inherent in natural gas and coal operations being subject to unexpected disruptions, including geological conditions, equipment failure,timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could 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;3•obtaining and renewing governmental permits and approvals for our natural gas and coal operations;•the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastesgenerated during our natural gas and coal operations;•our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection 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 natural gas well or amine;•the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or currentgas and coal operations;•the effects of mine closing, reclamation, gas well closing and certain other liabilities;•uncertainties in estimating our economically recoverable gas and coal reserves;•defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas or coal rights on some of ourproperties or failing to acquire these additional rights may result in a reduction of our estimated reserves;•the impacts of various asbestos litigation claims;•the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;•increased exposure to employee-related long-term liabilities;•lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in aplan year;•acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses andtheir risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may havemade and divestitures we anticipate may not occur or produce anticipated proceeds;•the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financialposition and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures;•risks associated with our debt;•replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline;•our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;•changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financialposition and profitability to deteriorate;•failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition;•failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which weguaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; and•other factors discussed in this 2013 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securitiesand Exchange Commission.4PART IITEM 1.BusinessGeneralCONSOL Energy is an integrated energy company operated through two primary divisions, oil and gas exploration and production (E&P) and coalmining. The E&P division is focused on Appalachian area natural gas and liquids activities, including production, gathering, processing and acquisition ofnatural gas properties in the Appalachian Basin. The coal division is focused on the extraction and preparation of coal, also in the Appalachian Basin.CONSOL Energy was incorporated in Delaware in 1991, but its predecessors had been mining coal, primarily in the Appalachian Basin, since 1864.CONSOL Energy entered the natural gas business in the 1980s initially to increase the safety and efficiency of our coal mines by capturing methane from coalseams prior to mining, which makes the mining process safer and more efficient. Over the past ten years, CONSOL Energy's natural gas business has grownby approximately 290% to produce 172.4 net Bcfe in 2013. This business has grown from coalbed methane production in Virginia into other unconventionalproduction, such as the Marcellus Shale and Utica Shale, in the Appalachian Basin.Our Gas Division operates, develops and explores for natural gas primarily in Appalachia (Pennsylvania, West Virginia, Virginia, Ohio, andTennessee). Currently, our primary focus is the continued development of our Marcellus Shale acreage and the exploration and development of our Utica Shaleacreage. We believe that our concentrated operating area, our legacy surface acreage position, our regional operating expertise, our geological logs from nearly100 years of shallow oil and gas drilling activity in the region, our held by production acreage position, and our ability to coordinate gas drilling with coalmining activity gives us a significant operating advantage over our competitors. We expect to produce 215-235 Bcfe for 2014 and achieve 30% annual gasproduction growth in 2015 and 2016.We are also party to two strategic joint ventures, one with Noble Energy, Inc. (Noble) in the Marcellus Shale and one with a subsidiary of HessCorporation (Hess) in the Utica Shale. These joint ventures require our partners to pay a portion of our qualifying drilling and completion cost's in certaincircumstances, which improves drilling economics and enables the acceleration of development of these assets.Our land holdings in the Marcellus Shale and Utica Shale plays cover large areas, provide multi-year drilling opportunities and, collectively, havesustainable lower risk growth profiles. We currently control approximately 446 thousand net acres in the Marcellus Shale and approximately 109 thousand netacres in the Utica Shale. In addition, we estimate that approximately 345 thousand net acres of our Marcellus Shale acreage in Pennsylvania and West Virginiaare prospective for the slightly shallower Upper Devonian Shale. We also have 2.5 million net acres in our coalbed methane play, primarily in Virginia.Highlights of our 2013 production include the following:•Total production of 472,274 Mcfe per day, an increase of 10% over 2012;•98% Natural Gas, 2% Liquids; and•34% Marcellus, 48% coalbed methane, 16% shallow oil & gas, 2% other.At December 31, 2013, our proved reserves had the following characteristics:•5.7 Tcfe of proved reserves;•97.5% natural gas;•43.9% proved developed;•85.7% operated; and•A reserve life ratio of 33.25 years (based on fourth quarter 2013 production); On December 5, 2013, we sold Consolidation Coal Company and certain subsidiaries, including five active coal mines in West Virginia, to asubsidiary of Murray Energy Corporation (the "Murray Energy Transaction"). These coal mines produced 26.7 million tons of thermal coal in 2013 and hadapproximately 1.1 billion tons of coal reserves. After the Murray Energy transaction, our coal division continues to focus on the extraction and processing ofcoal primarily in Pennsylvania and Virginia.5Highlights of coal activities from continuing operations in 2013 include the following:•Underground mining complexes are among the safest in the United States of America;•Production of 28.5 million tons of coal from continuing operations;•Coal reserve holdings of 3.0 billion tons;•30% of sales delivered to export markets;•59% of sales to domestic utilities; and•New BMX Mine in southwest Pennsylvania scheduled to come on-line in March 2014, as planned.Additionally, we provide energy services, including terminal services (the Baltimore Terminal), industrial supply services, water services and landresource management services.The following map provides the location of CONSOL Energy's gas and coal operations by region:CONSOL Energy's StrategyCONSOL Energy's strategy is to increase shareholder value through growth of its existing gas assets, selective acquisition of gas and liquids acreageleases within its footprint, and through participation in the forecasted global growth of thermal and metallurgical coal markets. We also will continue to focuson monetization of assets to accelerate value creation to minimize the shortfall between operating cash flows and our growth capital requirements.CONSOL Energy intends to continue to grow its gas production. The 2014 gas production guidance range is 215-235 Bcfe, net to CONSOLEnergy, of which 5-8% is expected to be liquids. For 2015 and 2016, the company expects 30% annual gas production growth.We expect natural gas to become a more significant contributor to the domestic electric generation mix as well as fueling industrial growth in the U.S.economy. Also, natural gas may potentially become a significant contributor to the transportation market. Our increasing gas production will allow CONSOLEnergy to participate in these growing markets.6The 2014 coal production guidance range is 30.1 - 32.1 million tons. CONSOL Energy’s coal assets align with the company’s long term strategicobjectives. The production from the company’s Pennsylvania Operations, which include the Bailey, Enlow Fork, and soon-to-be-completed BMX mines, canbe sold domestically or abroad, as either thermal coal or high volatile metallurgical coal. These low-cost mines, with five longwalls, and with estimatedproduction of nearly 24 million tons in 2014, produce a high-Btu Pittsburgh-seam coal that is lower in sulfur than many Northern Appalachian coals. Also,the company’s Buchanan Mine in southwestern Virginia produces a premium low volatile metallurgial coal for the steel industry. It typically produces 4-5million tons per year at a cost that is among the lowest of any domestic metallurgical coal mine.These mines along with the 100%-owned Baltimore Terminal, will continue to allow CONSOL Energy to participate in the growth of the world’sthermal and metallurgical coal markets. The International Energy Agency (IEA) forecasts meaningful continued growth in world demand for thermal coal. Theability to serve both domestic and international markets with premium thermal and metallurgical coal provides tremendous optionality.CONSOL Energy defines itself through its core values which are:•Safety,•Compliance, and•Continuous Improvement.These 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, allows management to create value for the long-term. The electric power industry generates overtwo-thirds of its output by burning natural gas or coal, the two fuels we produce. We believe that the use of natural gas and coal 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 potentially natural gas.CONSOL Energy's Capital Expenditure Budget- The following table outlines CONSOL Energy's capital expenditure budget for 2014: Capex ($MM)Natural Gas Operations: Land and Permitting: $70Liquids-rich drilling and completions: Marcellus 410Utica 105Dry-gas drilling and completions: Marcellus/Upper Devonian 415Utica 10CBM/Shallow Gas 40Midstream: Marcellus Gathering 60Total Natural Gas Operations $1,110 Coal Operations: BMX Mine $200Maintenance of Production 130Land/Safety/Water/Terminal 60Total Coal Operations $390 Total Company $1,5007CONSOL Energy expects to invest about $1.1 billion in its natural gas operations, much of which will be directed toward drilling and completion costsin the highly productive Marcellus and Utica shales. Approximately one-half of the company’s total drilling capital will target the liquids-rich areas withinthese two plays. On the dry gas side, drilling will primarily focus on those areas in the Marcellus shale that have established economics resulting from highnet revenue interest, economies of scale, or reservoir performance.Our joint venture partner is required to pay a portion of our drilling and completion costs in the certain circumstances. However, the Marcellus shaledrilling and completions capital is not reduced because of the contingent nature of the drilling carry in place with the Marcellus shale joint venture. TheMarcellus shale joint venture drilling carry is currently suspended and will be reinstated upon Henry Hub natural gas prices being equal to or greater than$4.00 per MMbtu for three consecutive months. Based on current Henry Hub futures and the expected corresponding reinstatement of the drilling carry,approximately $220 million of the Marcellus shale joint venture drilling carry is expected to be realized for drilling and completions capital incurred betweenMarch and December of the current year.The Utica shale drilling and completions capital reflects a $115 million reduction for drilling carry we expect to be paid by our joint venture partner.DETAIL GAS OPERATIONSOur Gas operations are located throughout Appalachia and include the following plays.Marcellus ShaleWe have the rights to extract natural gas in Pennsylvania, West Virginia, Ohio and New York from approximately 446,000 net Marcellus Shale acres atDecember 31, 2013.CONSOL Energy and Noble Energy, our joint venture partner, drilled a record 117 gross wells in the Marcellus Shale in 2013. CONSOL Energydrilled 46 of those wells in the dry gas area of the formation. The geographic breakdown was as follows:•26 wells in Southwestern Pennsylvania,•10 wells in Central Pennsylvania,•10 wells in Northern West Virginia, and•71 wells drilled by Noble Energy in the wet gas area of the play.CONSOL Energy also completed 59 Marcellus Shale wells in 2013. The average lateral length was 5,744 feet in 2013, or a 4% increase over theprevious year's lateral length of 5,514 feet. These longer drilled laterals enabled the company to perform more hydraulic fracturing, or “fracking,” to completethe wells. In 2013, the average completed well had 26 "frac" stages, or a 44% increase over the 18 stages from the previous year. Longer lateral lengths andmore "frac" stages per well are expected to enhance well economics.In 2014, the company expects Marcellus Shale drilling activity to be the primary driver of gas production growth. In the Marcellus Shale joint venture,CONSOL Energy and Noble Energy plan to operate an average of 4-5 horizontal rigs each to drill at least a combined 162 gross wells. At least 88 of the jointventure wells will be drilled in the liquids-rich areas of the play, including 2 within the recently acquired acreage that lies beneath the Pittsburgh InternationalAirport. At least 74 wells are planned to target the dry gas area of the joint venture. These dry locations include 6 Upper Devonian laterals (5 Burkett; 1Rhinestreet) in Washington County, Pennsylvania (4) and Doddridge County, West Virginia (2). Current plans of both partners include increased usage ofshorter stage laterals and reduced cluster spacing. The early results of these enhanced completion techniques in Southwestern Pennsylvania have been verypromising. The wells completed in this manner have shown initial production rates being improved by as much as 40%, which the company believes willtranslate into potential increases to well EURs of 15%-20%.We also hold a 50% interest in a gathering company which builds and operates the gathering system for most of our Marcellus shale production. Wecontributed our existing Marcellus Shale gathering assets to this company as of September 30, 2011. Joint operations are conducted in accordance with a jointdevelopment agreement.8UticaCONSOL Energy also controls approximately 109,000 net acres of Utica Shale potential in eastern Ohio at December 31, 2013. Additionally, CONSOLEnergy controls a large number of acres in southwestern Pennsylvania and northern West Virginia that contain the rights to the Utica Shale. These acres aredisclosed in other plays because the Utica Shale is not the primary drilling target as of December 31, 2013. The thickness of the Utica Shale in these areasrange from 200 to 450 feet.In 2013, CONSOL Energy and Hess, our joint venture partner, drilled 24 gross wells in the Utica. CONSOL Energy drilled 9 of those wells.In the Utica Shale joint venture, a total of 32 gross wells are planned to be drilled in 2014 within the liquids-rich corridor that runs across Harrison,Belmont, Guernsey, and Noble counties of Ohio. CONSOL Energy and its partner will also test enhanced completion techniques in the Utica as efforts in2014 will focus on ramping up production.We and our joint venture partner are seeking to monetize approximately 62,000 gross joint venture Utica shale acres which are located outside of our coreoperating area.Separate from the joint venture activity, CONSOL Energy expects to invest $24 million in Monroe County, Ohio in 2014. In addition to continuing tobuild-out its land position, the company will drill two 100%-owned wells. One well will target the liquids-rich Marcellus formation, while the other will bedesigned to penetrate the dry-gas Utica zone. Both will be drilled from the same pad.Coalbed Methane (CBM)We have the rights to extract CBM in Virginia from approximately 267,000 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. For 2014, the coalbedmethane program will again be kept at minimal drilling levels, with the expected drilling of 71 wells. Total capital for the 2014 CBM drilling program isestimated to be $34 million.We also have the right to extract CBM in West Virginia, southwestern Pennsylvania, and Ohio from approximately 965,000 net CBM acres. In centralPennsylvania we have the right to extract CBM from approximately 263,000 net CBM acres. In addition, we control 808,000 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, and 20,000 net acres in the PowderRiver Basin. We have no plans to drill CBM wells in these areas in 2014.Shallow Oil and GasThe shallow oil and gas acreage position of CONSOL Energy is approximately 906,000 net acres mainly in Illinois, Indiana, Kentucky, West Virginia,Pennsylvania, Virginia, and New York at December 31, 2013. The majority of our shallow oil and gas leasehold position is held by production and all of it isextensively overlain by existing third party gas gathering and transmission infrastructure. The shallow oil and gas assets provide multiple synergies with ourCBM and unconventional shale operations, and the held by production nature of the shallow oil and gas properties affords CONSOL Energy considerableflexibility to choose when to exploit those and other gas assets including shale assets. For 2014, the company continues to de-emphasize its shallow oil and gasprogram, and plans to drill a total of 5 wells.Other GasUpper DevonianThe Upper Devonian Shale formation lies above the Marcellus Shale formation in southwestern Pennsylvania and northern West Virginia. The companyholds a large number of acres that have Upper Devonian potential; generally these acres have not been disclosed separately, since they are not the primarydrilling target as of December 31, 2013.CONSOL Energy's first Upper Devonian well, which was drilled in the Burkett Shale and turned in line in June 2013, continues to demonstrate ashallow decline rate and an EUR in the range of 5-6 Bcfe. CONSOL Energy expects to drill five additional Burkett Shale wells in 2014, as well as at least oneRhinestreet Shale formation well. Our Marcellus Shale joint venture partner owns a 50% interest in the Burkett Shale formation within the joint venture area ofmutual interest, while CONSOL Energy controls a 100% interest in the Rhinestreet Shale formation.9ChattanoogaThe 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 243,000 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.HuronWe have 406,000 net acres of Huron Shale potential in Kentucky, West Virginia, and Virginia; a portion of this acreage has tight sands potential.Summary of Properties as of December 31, 2013 Shallow Oil CBM and Gas Marcellus Other Gas Segment Segment Segment Segment TotalEstimated Net Proved Reserves (MMcfe) 1,544,970 582,846 3,373,093 230,305 5,731,214Percent Developed 73% 100% 21% 34% 44%Net Producing Wells (including gob wells) 4,310 8,324 132 108 12,874Net Acreage Position Net Proved Developed Acres 258,601 248,318 11,527 9,247 527,693Net Proved Undeveloped Acres 9,986 — 44,396 4,964 59,346Net Unproved Acres(1) 2,193,699 625,706 380,964 1,011,661 4,212,030 Total Net Acres(2) 2,462,286 874,024 436,887 1,025,872 4,799,069_________(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. See Risk Factors in Section 1A. of this Form 10-K.(2)Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acres may include rights to multiple gasseams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect theacres in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.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, 2013, the number of producing wells, developed acreage and undeveloped acreage: Gross Net(1)Producing Wells (including gob wells) 15,063 12,874Net Acreage Position Proved Developed Acreage 542,388 527,693Proved Undeveloped Acreage 105,019 59,346Unproven Acreage 5,396,659 4,212,030 Total Acreage 6,044,066 4,799,069___________(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 various10properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section1A. of this Form 10-K. Development Wells (Net)During the years ended December 31, 2013, 2012 and 2011 we drilled 139.8, 95.5 and 254.9 net development wells, respectively. Gob wells and wellsdrilled by operators other than our primary joint venture partners, Noble Energy and Hess Corporation, are excluded from net development wells. In 2013,there were 205 gross development wells. There were no dry development wells in 2013, 2012, or 2011. As of December 31, 2013, there are 31 netdevelopmental wells still in process. The following table illustrates the net wells drilled by well classification type: For the Year Ended December 31, 201320122011 CBM segment 63.8 42.5 221.4 Shallow Oil and Gas segment 5.0 2.0 4.0 Marcellus segment 56.0 44.0 17.5(A)Other Gas segment 15.0 7.0 12.0 Total Development Wells 139.8 95.5 254.9 (A) For the year ended December 31, 2011, the Marcellus Segment includes 15 gross development wells drilled prior to September 30, 2011. A 50%interest in these wells was sold to Noble Energy on September 30, 2011.Exploratory Wells (Net)During the years ended December 31, 2013, 2012 and 2011, we drilled in the aggregate 5.5, 22.0, and 69.5 net exploratory wells, respectively. As ofDecember 31, 2013, there is 1.0 net exploratory well in process. In 2013, there were 11.0 gross exploratory wells. The following table illustrates the exploratorywells drilled by well classification type: For the Year Ended December 31, 2013 2012 2011 Producing Dry Still Eval. Producing Dry Still Eval. Producing Dry Still Eval.CBM segment — — — — — — — — —Shallow Oil and Gas segment — — — 4.0 7.0 4.0 12.0 1.0 1.0Marcellus segment 0.5 — 2.0 0.5 — 0.5 47.5 1.0 —Other Gas segment (1) — — 3.0 1.0 0.5 4.5 5.5 — 1.5 Total 0.5 — 5.0 5.5 7.5 9.0 65.0 2.0 2.5(1) For the year ended December 31, 2013, the Other Gas Segment includes three net exploratory wells drilled in the Utica Shale in Ohio, all of whichare still being evaluated.For the year ended December 31, 2012, the Other Gas Segment includes five net exploratory wells drilled in the Utica Shale in Ohio.For 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 Energy on September 30, 2011. There were a total of 15 gross exploratory wells drilled after September30, 2011 under the joint venture agreement with Noble Energy 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 under11current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securitiesand Exchange Commission (SEC). Net Reserves (Million cubic feet equivalent) as of December 31, 2013 2012 2011Proved developed reserves 2,514,294 2,165,483 2,135,805Proved undeveloped reserves 3,216,920 1,827,975 1,344,222Total proved developed and undeveloped reserves(a) 5,731,214 3,993,458 3,480,027___________(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.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) 2013 2012 2011Future net cash flows $6,568 $2,792 $4,877Total PV-10 measure of pre-tax discounted future net cash flows (1) $2,780 $1,242 $2,861Total standardized measure of after tax discounted future net cash flows $1,681 $736 $1,747____________(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.12Reconciliation of PV-10 to Standardized Measure As of December 31, 2013 2012 2011 (Dollars in millions)Future cash inflows $21,603 $11,778 $14,804Future production costs (7,106) (4,824) (5,263)Future development costs (including abandonments) (3,903) (2,451) (1,675)Future net cash flows (pre-tax) 10,594 4,503 7,86610% discount factor (7,814) (3,261) (5,005)PV-10 (Non-GAAP measure) 2,780 1,242 2,861Undiscounted income taxes (4,026) (1,711) (2,989)10% discount factor 2,927 1,205 1,875Discounted income taxes (1,099) (506) (1,114)Standardized GAAP measure $1,681 $736 $1,747Gas ProductionThe following table sets forth net sales volumes produced for the periods indicated: For the Year Ended December 31, 2013 2012 2011GAS Marcellus Sales Volumes (MMcf) 55,048 35,853 26,863CBM Sales Volumes (MMcf) 82,867 88,149 92,360Shallow Oil and Gas Sales Volumes (MMcf) 27,457 28,684 31,731Other Sales Volumes (MMcf) 3,365 2,366 1,987LIQUIDS* NGLs Sales Volumes (MMcfe) 2,628 610 —Oil Sales Volumes (MMcfe) 634 600 563Condensate Sales Volumes (MMcfe) 381 63 —TOTAL (MMcfe) 172,380 156,325 153,504*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil andnatural gas.CONSOL Energy projects its 2014 natural gas production to be between 215 - 235 Bcfe, of which 5%-8% is expected to be NGLs/condensates/oil.With the continued focus on the liquids-rich areas of its plays, the company expects that mix to increase to 10%-15% by the end of 2016, while overallvolumes are expected to increase 30% per year over the the same time period.Average 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.13 For the Year Ended December 31, 2013 2012 2011Total Average Gas Sales Price Before Effects of Financial Settlements (per Mcfe) $3.85 $3.00 $4.27Average Effects of Financial Settlements (per Mcfe) $0.45 $1.22 $0.63Total Average Gas Sales Price Including Effects of Financial Settlements (per Mcfe) $4.30 $4.22 $4.90Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe) $0.56 $0.58 $0.69We 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, we have delivered quantities required under these contracts. We also enter into various gas swaptransactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions and representedapproximately 84.3 Bcf of our produced gas sales volumes for the year ended December 31, 2013 at an average price of $4.68 per Mcf. These gas swapsrepresented approximately 76.9 Bcf of our produced gas sales volumes for the year ended December 31, 2012 at an average price of $5.25 per Mcf. As ofJanuary 21, 2014, we expect these transactions will represent approximately 129.3 Bcf of our estimated 2014 production at an average price of $4.61 per Mcf,78.6 Bcf of our estimated 2015 production at an average price of $4.10 per Mcf, and 71.3 Bcf of our estimated 2016 production at an average price of $4.20per Mcf.CONSOL Energy continues to develop a diversified portfolio of firm capacity transportation options to support our three-year production growth plan. We are benefited from the strategic location of our primary production areas in Southwest Pennsylvania, Northern West Virginia, and Eastern Ohio. Theseareas are served by a large concentration of major pipelines that provide us with the capacity to move our production to the major gas markets.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 has acquired extensive gathering assets. CONSOL Energy now owns or operates approximately 4,600miles of gas gathering pipelines as well as 250,000 horsepower of compression, of which, approximately 75% is wholly owned with the balance beingleased. Along with this compression capacity, CONSOL Energy owns and operates a number of gas processing facilities. This infrastructure is capable ofdelivering 300 billion cubic feet per year of pipeline quality gas.CONSOL Energy also owns 50% of CONE Gathering, LLC ("CONE" or "CONE Gathering") along with Noble Energy owning the other 50% interest.CONE Gathering develops, operates and owns both Noble Energy's and CONSOL Energy's Marcellus Shale gathering system needs. CONSOL Energyoperates this equity affiliate. We believe that the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems inthe Appalachian basin will give CONE Gathering an advantage in building the midstream assets required to develop the joint venture's Marcellus Shaleposition.In the Utica Shale, we and our joint venture partner, Hess, are primarily contracting with third parties for gathering services.CONSOL Energy has had the advantage of having gas production from CBM, which can be lower Btu than pipeline specification, as well as higherBtu Marcellus Shale production which can complement each other by reducing and in some cases eliminating the need for the costly processing of CBM. Inaddition, both our lower Btu CBM and dry Marcellus 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 Shale wells on-line at qualities that meet interstate pipelinespecifications. 14Natural Gas CompetitionThe United States natural gas industry is highly competitive and more diversified than the coal industry. CONSOL Energy competes with other largeproducers, as well as thousands of smaller producers, pipeline imports from Canada, and Liquefied Natural Gas (LNG) from around the globe. According todata from the Natural Gas Supply Association and the Energy Information Agency (EIA), the five largest producers of natural gas produced about 20% of drynatural gas production in the first six months of 2013. The EIA reported 482,822 producing natural gas wells in the United States in 2012, the latest year forwhich government statistics are available.Natural gas has lost three percent of market share in the U.S. electric generation market compared to record natural gas generation in 2012 (based onpreliminary 2013 results). However, we expect natural gas to become a more significant contributor to the domestic electric generation mix in the long-term, aswell as fuel industrial growth in the U.S. economy. There is potential for natural gas to become a significant contributor to the transportation market.Additionally, the U.S. is expected to become a net exporter of gas in the next few years. Our increasing gas production will allow CONSOL Energy toparticipate in these growing markets.CONSOL Energy's gas operations are primarily located in the eastern United States. The gas market is highly fragmented and not dominated by anysingle producer. We believe that competition within our market is based primarily on natural gas commodity trading fundamentals and pipeline transportationavailability to the various markets.Continued demand for CONSOL Energy's natural gas and the prices that CONSOL Energy obtains are affected by natural gas use in the production ofelectricity, U.S. manufacturing and the overall strength of the economy, environmental and government regulation, technological developments and theavailability and price of competing alternative fuel supplies.DETAIL COAL OPERATIONSCoal ReservesAt December 31, 2013, CONSOL Energy had an estimated 3.0 billion tons of proven and probable reserves, excluding equity affiliates. Reserves are theportion of the proven and probable tonnage that meet CONSOL Energy's economic criteria regarding mining height, preparation plant recovery, depth ofoverburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.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 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. In previous years, the independent consultant has reviewed the procedures used by us toprepare our internal estimates, verified the accuracy of our property reserve estimates and retabulated reserve groups according to standard classifications ofreliability.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. 15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 reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex tomine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continuethe 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 below, 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.16Mining ComplexesThe following table provides the location of CONSOL Energy's active mining complexes and the coal reserves associated with each of the continuingoperations.CONSOL ENERGY MINING COMPLEXESProven and Probable Assigned and Accessible Coal Reserves as of December 31, 2013 and 2012 Recoverable Average As Received Heat Reserves(2) Seam Value(1) Tons in Reserve Coal Thickness (Btu/lb) Owned Leased MillionsMine/Reserve Location Class Seam (feet) Typical Range (%) (%) 12/31/2013 12/31/2012ASSIGNED–OPERATING (4) Thermal Reserves Enlow Fork (3) Enon, PA Assigned Pittsburgh 5.4 12,920 12,760 –13,020 100% —% 16.9 27.0 Accessible Pittsburgh 5.3 13,020 12,830 –13,100 79% 21% 232.8 232.8Bailey (3) Enon, PA Assigned Pittsburgh 5.5 12,940 12,840 –13,000 62% 38% 96.9 92.2 Accessible Pittsburgh 5.7 12,940 12,770 –13,090 88% 12% 278.7 303.0Amvest-Fola Complex (3) Bickmore, WV Assigned Multiple 4.6 12,380 12,250 –12,550 86% 14% 73.4 73.4Miller Creek Complex Delbarton, WV Assigned Multiple 2.6 12,050 11,600 –12,650 44% 56% 52.6 13.4 Accessible Multiple 5.1 12,610 12,610 –12,610 1% 99% 0.7 8.2 Metallurgical Reserves Buchanan Mavisdale, VA Assigned Pocahontas 3 6.2 13,740 13,610 –14,130 20% 80% 47.2 51.7 Accessible Pocahontas 3 5.9 13,720 13,630 –13,870 14% 86% 46.1 46.3Amonate Complex Amonate, VA Assigned Multiple 4.2 13,150 12,850 –13,350 64% 36% 20.1 14.8 Accessible Multiple 5.2 13,010 13,010 –13,010 100% —% 6.6 6.6Total Assigned Operating andAccessible 872.0 869.417_____________(1)The heat value shown for Assigned Operating reserves is based on the quality of coal mined and processed during the year ended December 31, 2013. Theheat value shown for accessible reserves are based on as received, dry values obtained from drill hole analysis prorated by the associated AssignedOperating reserve values to account for similar mining and processing methods.(2)Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness and average density determined by 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)A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.(4)The table excludes 57 million tons of recoverable reserves which represents CONSOL Energy's portion of tonnage held by two equity affiliates. CONSOLEnergy owns a 49% interest in both of these affiliates.The following table sets forth our unassigned proven and probable reserves by region:CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2013 and 2012 Recoverable Recoverable Reserves(2) Reserves Tons in (tons in As Received Heat Owned Leased Millions Millions)Coal Producing Region Value(1) (Btu/lb) (%) (%) 12/31/2013 12/31/2012Northern Appalachia (Pennsylvania, Ohio, Northern WestVirginia) 11,400 – 13,600 86% 14% 951.7 1,424.0Central Appalachia (Virginia, Southern West Virginia) 11,400 – 14,100 54% 46% 349.6 354.7Illinois Basin (Illinois, Western Kentucky, Indiana) 11,600 – 12,000 45% 55% 731.9 733.6Total 65% 35% 2,033.2 2,512.3_______________(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, unassigned reserves are based primarily on exploration drill core datathat may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.(2)Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by 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. Reserves are only reported for those coal seams that arecontrolled by ownership or leases.18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, 2013 ≤ 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(1): High Vol A Bituminous — — 6.2 — — 208.7 — — — 214.9 7.1% Med Vol Bituminous — 5.1 56.1 — — 2.9 — — — 64.1 2.1% Low Vol Bituminous — — 186.6 — — 55.2 — — — 241.8 8.0% Total Metallurgical — 5.1 248.9 — — 266.8 — — — 520.8 17.2%Thermal(1): High Vol A Bituminous 34.5 80.4 2.8 41.5 105.2 61.5 66.8 62.2 1,289.7 1,744.6 57.5% High Vol B Bituminous — 17.9 — — 75.4 — — 401.1 — 494.4 16.3% High Vol C Bituminous — — — — 159.4 — 108.3 — — 267.7 8.8% Low Vol Bituminous — — — — — — — — 4.5 4.5 0.2% Total Thermal 34.5 98.3 2.8 41.5 340.0 61.5 175.1 463.3 1,294.2 2,511.2 82.8% Total 34.5 103.4 251.7 41.5 340.0 328.3 175.1 463.3 1,294.2 3,032.0 100.0% Percent of Total 1.1% 3.4% 8.3% 1.4% 11.2% 10.8% 5.8% 15.3% 42.7% 100.0% The table above excludes 57 million tons of reserves held by two equity affiliates. CONSOL Energy owns 49% of both of these affiliates.Title 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.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, 2013, 2012 and 2011. Total Total Total Royalty Coal Royalty Tonnage Acreage IncomeYear (in thousands) Leased (in thousands)2013 8,335 271,755 $16,9062012 8,326 271,760 $16,8532011 8,488 289,833 $17,969Royalty 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.19ProductionIn the year ended December 31, 2013, 94% of CONSOL Energy's production from continuing operations came from underground mines and 6% fromsurface mines. Where the geology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. Forthe year ended December 31, 2013, 90% of our production came from mines equipped with longwall mining systems. Underground longwall systems arehighly mechanized, 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.The following table shows the production from continuing operations, in millions of tons, for CONSOL Energy's mines for the years endedDecember 31, 2013, 2012 and 2011, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation and theyear each mine was established or acquired by us. Tons Produced Year Mine Mining (in millions) EstablishedMine Location Type Equipment Transportation 2013 2012 2011 or AcquiredThermal Bailey (3) Enon, PA U LW/CM R R/B 10.1 8.6 8.6 1984Enlow Fork (3) Enon, PA U LW/CM R R/B 8.9 8.0 8.3 1990Miller Creek Complex(2) Delbarton, WV U/S CM/S/L R T 2.2 2.9 2.8 2004AMVEST-Fola Complex(1)(2) Bickmore, WV U/S A/S/L/CM R T — 0.8 2.1 2007High Volatile Metallurgical Bailey-Met (3) Enon, PA U LW/CM R R/B 1.3 1.5 2.1 1984Enlow Fork-Met (3) Enon, PA U LW/CM R R/B 1.2 1.5 1.8 1990AMVEST-Fola Complex(1)(2)-Met Bickmore, WV U/S A/S/L/CM R T — 0.3 0.1 2007AMVEST-Terry Eagle Complex(1)(2)-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 4.8 3.5 5.7 1983Amonate (1)(2) Amonate, VA U/S A/S/CM R T — 0.1 — 2012Total 28.5 27.2 31.6 CONSOL Energy Portion of Equity Affiliates Harrison Resources(2)(4) Cadiz, OH S S/L R T 0.4 0.4 0.4 2007Western Allegheny-Knob Creek(2)(4) Young Township, PA U CM R T 0.3 0.1 0.1 2010Total CONSOL Energy Portion of Equity Affiliates 0.7 0.5 0.5 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)–Harrison Resources, Miller Creek Complex, AMVEST–Fola Complex, AMVEST–Terry Eagle Complex, Amonate Complex and Western Allegheny–Knob Creek includefacilities operated by independent contractors.(3)–Mine was idle for three weeks during 2012 due to a structural failure at the above-ground conveyor system at the Bailey Preparation Plant. Production was then resumed ata reduced capacity.(4)–Production amounts represent CONSOL Energy's 49% ownership interest.20Coal CapitalCoal operations anticipate investing $200 million in 2014 to complete the BMX Mine in mid-March. This underground mine is adjacent to CONSOLEnergy’s Bailey and Enlow Fork mines in Southwestern Pennsylvania. On a full-year basis, the single-longwall BMX Mine is expected to produceapproximately 5 million annual tons of high-quality Pittsburgh seam coal to be sold in either the high volatile metallurgical or thermal markets.Due to the well capitalized nature of the company’s retained coal assets, we anticipate that maintenance-of-production capital for 2014 will be held tounder $4.25 per ton on the 31 million tons expected to be produced for the year. Coal Marketing and SalesOur sales of bituminous coal from continuing operations were at average sales price per ton sold as follows: Years Ended December 31, 2013 2012 2011Average Sales Price Per Ton Sold– Thermal Coal $64.78 $69.08 $66.84Average Sales Price Per Ton Sold– High Volatile Met Coal $63.44 $63.93 $78.57Average Sales Price Per Ton Sold– Low Volatile Met Coal $92.64 $140.11 $191.81Average Sales Price Per Ton Sold– Total Company $69.34 $77.75 $90.10We 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 from continuing operations is as follows: Tons Percent of Sold TotalThermal 21.4 74%High Volatile Metallurgical 2.5 9%Low Volatile Metallurgical 4.9 17%Total tons sold 28.8 100%Approximately 59% of our 2013 coal sales from continuing operations were made to U. S. electric generators, 30% of our 2013 coal sales were priced onexport markets and 11% of our coal sales were made to other domestic customers. We had over 60 customers from our 2013 continuing operations. During2013, Xcoal Energy Resources and Duke Energy Carolinas each comprised over 10% of our revenues from continuing operations, and the top four coal andgas customers accounted for more than 35% of our total revenues from continuing operations.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, 2013, over 70% of all the coal we produced from continuing operations was sold under contracts with terms of one year or more. The following table sets forth as of January 22, 2014, CONSOL Energy's estimated production and sales for 2014 through 2015.21COAL DIVISION GUIDANCE(Tons in millions) Q1 2014 2014 2015 Est. Total Coal Sales 7.2 - 7.6 30.1 - 32.1 34.0 Tonnage: Firm 6.9 23.8 12.2 Price: Sold (firm) $64.75 $65.35 $69.23 Est. Low-Vol Met Sales 1.1 - 1.2 4.2 - 4.7 4.9 Tonnage: Firm 0.8 1.7 0.8 Est. High-Vol Met Sales 0.7+ 2.3+ 2.4 Tonnage: Firm 0.6 0.9 0.3 Est. Thermal Sales 5.6+ 23.8+ 26.7 Tonnage: Firm 5.5 21.2 11.1 Note: While most of the data in the table are single point estimates, the inherent uncertainty of markets and mining operations means that investorsshould consider a reasonable range around these estimates. CONSOL Energy has chosen not to forecast prices for open tonnage due to ongoingcustomer negotiations. Firm tonnage is tonnage that is both sold and priced, and excludes collared tons. There are no collared tons in 2014. Collaredtons in 2015 are 1.4 million tons, with a ceiling of $72.59 per ton and a floor of $48.59 per ton. Not included in the category breakdowns are the tonsfrom equity affiliates Harrison Resources and Western Allegheny Energy (WAE). Harrison Resources has 0.1 million tons for Q1 2014, and 0.4 milliontons for all of 2014 and 2015. WAE has 0.1 million tons for Q1 2014, and 0.5 million tons and 0.9 million tons for all of 2014, and 2015, respectively.Coal pricing for contracts with terms of one year or less is generally fixed. Coal pricing for multiple-year agreements generally provide the opportunity toperiodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:•Fixed price contracts with pre-established prices;•Periodically negotiated prices that reflect market conditions at the time;•Price restricted to an agreed-upon percentage increase or decrease; or•Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices.The 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, unexpected significant geological conditions or natural disasters. Depending on the language of thecontract, 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 railroad cars, trucks or a combination of these means of transportation.We employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines,terminal operators, ocean vessel brokers and trucking companies for certain customers.Coal CompetitionThe United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. CONSOL Energy competesagainst several other large producers and numerous small producers in the United States and overseas. Demand for our coal by our principal customers isaffected 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, wind or solar;•environmental and government regulation;•coal quality;22•transportation costs from the mine to the customer;•the reliability of fuel supply;•worldwide demand for steel;•natural/weather disasters; and•political changes in international governments.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.Other OperationsCONSOL Energy provides other services both to our own operations and to others. These include land services, industrial supply services, terminalservices and water services.Non-Core Mineral Assets and Surface PropertiesCONSOL Energy owns significant gas and coal 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 27 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. CONSOL Energy's coal and gas divisionsaccounted for 37% of Fairmont Supply's sales in 2013.Terminal ServicesIn 2013, approximately 10.2 million tons of coal were shipped through CONSOL Energy's subsidiary, CNX Marine Terminals Inc.'s, exportingterminal in the Port of Baltimore. Approximately 21% 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. Water ServicesCNX Water Assets LLC, a CONSOL Energy subsidiary, is acquiring and developing existing sources of water in order to support our gas and coaloperations, develop business in water sales, promote cutting edge water technologies, treat both acid mine drainage (AMD) water and fracturing water, andreduce our environmental liabilities. CNX Water Assets' operate an advanced waste water treatment plant in support of coal operations as well as fresh waterreservoirs. CNX Water Assets' objective is to develop and maximize the value of existing water assets, which will be used to provide water for drilling andhydraulic fracturing in support of gas operations and meeting the needs of mining operations. CNX Water Assets' also has contracts to provide water to thirdparties for industrial use from various water sources owned by CONSOL Energy. Employee and Labor RelationsAt December 31, 2013, CONSOL Energy had 4,633 employees. Less than 1% of the total workforce is represented by the United Mine Workers ofAmerica (UMWA).23Industry SegmentsFinancial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years endedDecember 31, 2013, 2012 and 2011 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.Laws and RegulationsOverviewOur gas and coal mining operations are subject to various types of federal, state and local regulations. Regulations relating to our operations includepermitting and other licensing requirements; water withdrawal and procurement for well stimulation purposes; well drilling and casing; well production; wellplugging; venting or flaring of natural gas; pipeline compression and transmission of natural gas and liquids; reclamation and restoration of properties aftergas or mining operations are completed; storage, transportation and disposal of materials used or generated by gas and mining operations; the calculation,reporting and disbursement of taxes; gathering of gas production in certain circumstances; surface subsidence from underground mining; discharge of waterfrom coal mining operations; air quality standards; protection of wetlands; endangered plant and wildlife protection; and employee health and safety.Numerous governmental permits and approvals under these laws and regulations are required for gas and mining operations. Lastly, the electric powergeneration industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for ourgas and coal products.Compliance with these laws has substantially increased the cost of gas production and mining of coal for all domestic gas and coal producers. We alsopost 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 gaswells. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamationand mine closing, often including the cost of treating mine water discharge. We endeavor to conduct our gas and mining operations in compliance with allapplicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements against a backdrop ofvariable geologic and seasonal conditions, permit exceedances and violations during gas and mining operations can and do occur. The possibility exists thatnew legislation or regulations may be adopted which would have a significant impact on our gas and coal mining operations or our customers' ability to useour gas and coal and may require us or our customers to change their operations significantly or incur substantial costs.CONSOL Energy made capital expenditures for environmental control facilities of approximately $1.6 million, $1.3 million, and $4.2 million in theyears ended December 31, 2013, 2012 and 2011, respectively. CONSOL Energy expects to have capital expenditures of $9.9 million in 2014 forenvironmental control facilities.Environmental LawsClean Air Act and Related Regulations. The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affectgas production and processing operations, as well as coal mining, coal handling and processing, primarily through permitting and/or emissions controlrequirements.We are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specificequipment, technologies or best management practices to control emissions. On August 16, 2012, the U.S. Environmental Protection Agency (EPA) publishedfinal revisions to the New Source Performance Standards (NSPS) to regulate emissions of volatile organic compounds (VOCs) and sulfur dioxide (SO2) fromvarious oil and gas exploration, production, processing and transportation facilities and revisions to the National Emission Standards for Hazardous AirPollutants (NESHAPS) to further regulate emissions from the oil and natural gas production sector and the transmission and storage of natural gas. InSeptember 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires annual reporting of emissionsfrom gas wells, coal mines and associated facilities.The Clean Air Act also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions of the coal firedelectric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which arereleased into the air when coal is burned. Carbon dioxide, a greenhouse gas, is also emitted when coal is burned. Environmental regulations governingemissions from coal fired electric generating plants could affect demand for coal as a fuel source and affect the volume of our sales. In 2012, the EPApromulgated or finalized several rulemakings impacting coal generating facilities. Two of these were final rules for new source performance standards24for coal and oil fueled power plants in the Utility Maximum Control Technology (UMACT) rule which includes more stringent new source performancestandards (NSPS) for particulate matter (PM), SO 2 and NO X and the Mercury and Air Toxics Standards (MATS) rule which sets new mercury and airtoxic standards. In November 2012, EPA published a notice of reconsideration of certain aspects of the UMACT and MATS rules. In April 2013, EPA issueda final version of its reconsideration of its UMACT and MATS rules. The reconsideration resulted in higher limits, but the standards are still stringent andcompliance will be expensive. In addition, in August 2012, the U.S. Court of Appeals in Washington, DC invalidated EPA's 2011 Cross-State Air PollutionRule which was intended to regulate sulfur dioxide (SO2), nitrogen dioxide (NOx) and fine particulate matter. The Court ruled that the agency had oversteppedits bounds and vacated the rulemaking, ordering the agency to continue to enforce the Clean Air Interstate Rule promulgated in 2005 until a viable replacementto the cross-state regulation could be issued. An appeal from the Circuit Court’s decision was argued before the U.S. Supreme Court in December 2013.In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide emissions from coal powered electricgenerating units. The proposed rules would have applied to new power plants and to existing plants that make major modifications. If the rules had beenadopted as proposed, the only new coal fired power plants that could have met the proposed emission limits would have been coal fired plants with carbondioxide capture and storage (CCS). Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal fired electricgeneration units uneconomical compared to new gas fired electric generation units. On January 8, 2014, EPA re-proposed NSPS for CO2 for new fossil fuelfired power plants and rescinded the rules that were proposed on April 12, 2012. These proposed rules will also require CCS for new coal fired power plants.Clean Water Act. The federal Clean Water Act (CWA) and corresponding state laws affect our gas and coal operations by regulating discharges intosurface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutantsinto regulated waters. The Clean Water Act and corresponding state laws include requirements for: improvement of designated "impaired waters" (not meetingstate water quality standards) through the use of effluent limitations; anti-degradation regulations which protect state designated "high quality/exceptional use"streams by restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides,selenium and dissolved solids; for minimizing impacts and compensating for unavoidable impacts resulting from discharges of fill materials to regulatedstreams and wetlands; and the requirements to dispose of produced wastes and other oil and gas wastes at approved disposal facilities. In addition, the SpillPrevention, Control and Countermeasure (SPCC) requirements of the CWA apply to all CONSOL Energy operations that use or produce fluids, includingbrine and oil, and require that plans be in place to address any spills and that secondary containment be installed around all tanks. These requirements maycause CONSOL Energy to incur significant 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 Marcellus and Utica shales. The EPA initiated the study in early January 2011 with a final report to be published in 2014. In 2012, EPA has alsoannounced plans to conduct a review of water produced in conjunction with the production of Coal Bed Methane (CBM) to determine whether its disposalshould be further regulated. In late 2013, EPA announced that it did not intend to continue with its effort to revise effluent limits for coalbed methaneoperations.CONSOL Energy utilizes pipelines extensively for its gas, water and coal businesses, and as such must obtain permits with associated mitigation fromthe Army Corps of Engineers (ACOE) for impacts to streams and wetlands that we are unable to avoid. In 2013, the EPA issued a draft report entitledConnectivity of Streams and Wetlands to Downstream Waters which affects a proposed rulemaking that would expand the scope of the Clean Water Act(CWA) to include previously non-jurisdictional streams, wetlands, and waters and make these areas jurisdictional inter-coastal Waters of the U.S. Thisrulemaking will likely cause states that have jurisdiction over their own waters to make regulatory changes to their already robust regulatory programs offeringlittle to no added environmental protection or benefit from the changes. This would only add unwarranted delays to the permitting process and extend reviewtimes even further for regulatory agencies already under resourced.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 ACOE and a discharge permit from the state regulatory authority under the state counterpart to the Clean Water Act.Beginning in early 2009, the EPA took a number of initiatives that have resulted in delays and obstruction of the issuance of such permits for surface miningoperation in the Appalachian states including Pennsylvania and Virginia where our principal mining complexes are located. Increased oversight of delegatedstate programmatic authority, coupled with individual permit review and additional requirements imposed by the EPA, has resulted25in delays in the review and issuance of permits for surface coal mining operations, including applications for surface facilities for underground mines, suchas applications for coal refuse disposal areas. The coal industry has had some success challenging EPA’s policies but EPA continues with its initiatives. Thusfar, CONSOL Energy subsidiaries have been able to continue operating their existing mines. There is no assurance that permits can be obtained for futuremining operations.In late June 2012, we received informal notification from the Pennsylvania Department of Environmental Protection of the Department's intent pursuantto a Technical Guidance Document entitled “Surface Water Protection-Underground Bituminous Coal Mining” to require a change in the mine plan of apending application for a permit for expansion of the Company's Bailey longwall mine. If ultimately required, this change in mine plan could have a materialeffect on our forecasted production for 2015. We do not agree that a modification of its mining plan is necessary to comply with applicable regulatoryperformance standards and we continue to submit information to the permitting authority to support our position. Additionally, we are currently evaluatingpotential modifications that would be required if we are compelled to modify our application.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 investigation and remediation of releases of hazardous substancesinto the environment and for damages to natural resources. We could incur liability under CERCLA relative to our gas or coal operations. We also mustcomply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.Resource Conservation and Recovery Act. The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulationsaffect gas operations and coal mining by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardouswastes have been treated, stored or disposed are subject to corrective action orders issued by the EPA which could adversely affect our results, financialcondition and cash flows. In 2010, the EPA proposed options for the regulation of Coal Combustion Residuals from the electric power sector as eitherhazardous waste or non-hazardous waste. A final decision is expected in 2014. Depending on the outcome of that decision, demand for coal fired electricitygeneration could be adversely impacted.Endangered Species Act. The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection ofendangered and threatened species may cause us to modify gas well pad siting or pipeline right of ways, mining plans, or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areaswhere we operate are protected under the ESA. Based on the species that have been identified and the current application of endangered species laws andregulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to producegas or mine coal from our properties. The US Fish and Wildlife Service (USFWS) announced a 12-month finding that listing of the Northern Long-Eared Batas endangered is warranted throughout the bat’s range. CONSOL Energy, along with others in industry have submitted comments against the listing. Thislisting will establish habitat protection for the species but will not prevent the cause of the decline in the population of the Long-Eared bat, which is due to adisease commonly referred to as White Nose Syndrome. This will lead to significant timing and critical path hurdles, ultimately limiting the ability to cleartimber for construction activities. Surface Mining Control and Reclamation Act. The federal Surface Mining Control and Reclamation Act (SMCRA) establishes minimum nationaloperational, reclamation and reclamation standards for all surface mines as well as most aspects of underground mines. SMCRA requires that comprehensiveenvironmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all miningoperations must be obtained from the U. S. Office of Surface Mining (OSM) or, where state regulatory agencies have adopted federally approved stateprograms under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which aremore stringent than the requirements of SMCRA and OSM's regulations and in many instances have done so. Our active mining complexes are located instates which have achieved primary jurisdiction for enforcement of SMCRA through approved state programs. In addition, SMCRA imposes a reclamation feeon all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (AML Fund), which is used to restoreunreclaimed and abandoned mine lands mined before 1977. The current per ton fee is $0.280 per ton for surface mined coal and $0.120 per ton forunderground mined coal. These fees are currently scheduled to be in effect until September 30, 2021.OSM is currently considering modifications to the existing stream buffer zone regulation, which amendments are referred to as the Stream ProtectionRule. OSM’s latest position is that proposed Stream Protection regulations will be published in August 2014. Although it is too early to predict what theimpacts of the proposed amendments will be, they could result in loss of access to significant amounts of coal and/or significant increases in reclamationcosts. In Pennsylvania, where we operate two longwall mines, approximately $16.0 million, $21.1 million and $25.7 million of expenses were incurred fromcontinuing operations during the years ended December 31, 2013, 2012 and 2011, respectively, to mitigate and repair impacts on streams26from subsidence. We currently estimate expenses related to subsidence of streams in Pennsylvania will be approximately $15.8 million for the year endedDecember 31, 2014.Federal Regulation of the Sale and Transportation of GasRegulations and orders set forth by the Federal Energy Regulatory Commission (FERC) impact our gas business to a certain degree. Although the FERCdoes not directly regulate our gas production activities, the FERC has stated that it intends for certain of its orders to foster increased competition within allphases of the natural gas industry. Additionally, the FERC continues to review its transportation regulations, including whether to allocate all short-termcapacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market biastoward short-term contracts. The FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previouslyowned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided by these facilities, then such facilities andservices may be subject to regulation by state authorities in accordance with state law. We own certain natural gas pipeline facilities that we believe meet thetraditional tests which the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.Health and Safety LawsOccupational Safety and Health Act. Our gas operations are subject to regulation under the federal Occupational Safety and Health Act (OSHA) andcomparable state laws in some states, all of which regulate health and safety of employees at our gas operations. Also, OSHA's hazardous communicationstandard requires that information be maintained about hazardous materials used or produced by our gas operations and that this information be provided toemployees, state and local governments and the public.Mine Safety. Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined outareas, and engage in additional training. We have also experienced more aggressive inspection protocols and with new regulations the amount of civil penaltieshave 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.According to a November 2013 regulatory update, in the first quarter of 2014 the Department of Labor intends to publish final rules for undergroundcoal mining operations concerning lowering coal miners exposure to respirable coal mine dust and concerning proximity detection systems for continuousmining machines. Proposed rules for concerning exposure of coal miners to crystalline silica and proximity detection systems for mobile machines inunderground mines are intended to be published in the second quarter of 2014. Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits orcontributions 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 up to$1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.The Patient Protection and Affordable Care Act (PPACA) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to thelegal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years inunderground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have toprove that a miner did not have27black lung or that the disease was not caused by the miner's work. Second, it changed the law so black lung benefits will continue to be paid to dependentsurvivors 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 statestatutes for black lung claims.Other State and Local Laws Related to Our Gas BusinessRegulation Affecting Gas Operations. Our gas operations are also subject to regulation at the state and in some cases, county, municipal and localgovernmental levels. Such regulation includes requiring permits for the siting and construction of well pads and roads, drilling of wells, bondingrequirements, protection of ground water and surface water resources and protection of drinking water supplies, the method of drilling and casing wells, thesurface use and restoration of well sites, gas flaring, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gasoperations producing coalbed methane in relation to active mining. A number of states have either enacted new laws or may be considering the adequacy ofexisting laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental and in somecircumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatoryscrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation ofrates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers.However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.Ownership of Mineral Rights. CONSOL Energy acquires ownership or leasehold rights to gas and coal properties prior to conducting operations onthose properties. As is customary in the gas and coal industries, we have generally conducted only a summary review of the title to gas and coal rights that arenot in our development plans, but which we believe we control. This summary review is conducted at the time of acquisition or as part of a review of our landrecords to determine control of mineral rights. Given CONSOL Energy's long history as a coal producer, we believe we have a well-developed ownershipposition relating to our coal control; however, our ownership of oil and gas rights, particularly those rights that we acquired in connection with our historiccoal operations and some of the rights we acquired in 2010 from Dominion are less developed. As we continue to review our land records and confirm title inanticipation of development, we expect that adjustments to our ownership position (either increases or decreases) will be required.Prior to the commencement of development operations on gas and coal properties, we conduct a thorough title examination and perform curative workwith respect to significant defects. We generally will not commence operations on a property until we have cured any material title defects on such property. Weare typically responsible for the cost of curing any title defects. In addition, the acquisition of the necessary rights may not be feasible in some cases. Ourdiscovering gas title defects which we are unable to cure may adversely impact our ability to develop those properties and we may have to reduce our estimatedgas reserves including our proved undeveloped reserves. We have completed title work on substantially all of our gas and coal producing properties and believethat we have satisfactory title to our producing properties in accordance with standards generally accepted in the industry.Available 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 ofCONSOL Energy” (included herein pursuant to Item 401 (b) of Regulation S-K).28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 a worldwide financial downturn,such as the 2008 - 2009 financial crisis, or negative credit market conditions may have lasting effects on our liquidity, business and financialcondition that we 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 from 2009 levels, the generaleconomic challenges continued in 2013 and the outlook is uncertain. In addition, liquidity is essential to our business. Although we cannot predict the impacts,renewed weakness in the economic conditions of any of the industries we serve, or another financial crisis, could adversely affect our business and financialcondition in a number of ways. 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 thermal coal as higher-priced high volatilemetallurgical 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 gas or coal reserves; and•our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcyprotection.An extended decline in demand for our products, or the prices CONSOL Energy receives for natural gas, natural gas liquids, and coal willadversely affect our operating results and cash flows.Our financial results are significantly affected by the demand for our products and the prices we receive for our natural gas, natural gas liquids, andcoal.Natural gas and natural gas liquids accounted for approximately 26% of our revenues from continuing operations in 2013. Natural gas prices are veryvolatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Prices for natural gas may fluctuatewidely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that arebeyond our control, such as:•the overall domestic supply of natural gas;•the supply of natural gas in our market;•changes in the consumption pattern of industrial consumers, electricity generators and residential users;•weather conditions;•proximity and capacity of gas pipelines and other transportation facilities;•overall domestic and global economic conditions;•the price and availability of alternative fuels, especially thermal coal; and•the price and supply of imported liquefied natural gas.In particular, while demand for natural gas has recovered to pre-recession levels, the U.S. natural gas industry continues to face concerns of oversupplydue to the success of Marcellus and other new shale plays. The oversupply of natural gas in 2012 resulted in domestic prices hovering around ten year lows,and drilling continued in these plays, despite lower gas prices, to meet drilling commitments. Our gas operations are geographically concentrated in the mid-Atlantic states and oversupply from the continued drilling in these plays, despite lower prices, directly affects prices we receive. Low gas prices adverselyimpacts our gas operations revenues and earnings before income taxes.29The success of the Marcellus Shale play and development of other Shale plays has resulted in growth in gas production in this region with productionper day in Pennsylvania, West Virginia and Ohio more than doubling since 2011. Traditionally, natural gas produced in the mid-Atlantic states sold at apremium to the benchmark Louisiana Henry Hub prices. However, as Appalachian production increased this premium narrowed. This decline, or negativebasis, to the Henry Hub price is forecasted to continue in future years and may widen due to anticipated further increased Appalachian gas production. Thus,apart from the general impact of domestic production on overall gas prices, the price paid for our natural gas also may be adversely affected by increasingproduction in our market.An extended period of lower natural gas prices could negatively affect us in several other ways. These include reduced cash flow, which would decreasefunds available for capital expenditures employed to replace reserves or increase production. For example, in light of the low natural gas prices during 2012,the number of wells drilled in our Noble joint venture during 2012 was significantly reduced from the number we initially planned to drill. Also, our access toother sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reducethe amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimatedproved reserves. If this occurs, or if our estimates 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 performimpairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows thatwould indicate that the carrying amount may not be recoverable or whenever management's plans change with respect to those assets. We may incurimpairment charges in the future, which could have an adverse effect on our results of operations in the period taken.We and our joint venture partners have increased drilling activity in areas of shale formations which may also contain natural gas liquids and/or oil. Theprices for natural gas liquids and oil are volatile for reasons similar to those described above regarding natural gas. Similar to the oversupply of natural gas,increased drilling activity in 2012 by third parties in formations containing natural gas liquids has led to a significant decline in the price of natural gasliquids. If we discover and produce significant amounts of natural gas liquids or oil, our results of operation may be adversely affected by downwardfluctuations in natural gas liquids and oil prices.The sale to Murray Energy in 2013 of almost one half or our thermal coal production increased our exposure to fluctuations in the price of coal, naturalgas and natural gas liquids.Coal accounted for approximately 66% of our revenues from continuing operations in 2013. Prices of and demand for our coal may fluctuate due tofactors beyond our control such as:•overall domestic and global economic conditions, technological advances affecting energy consumption, price and availability of foreign coal, anddomestic and foreign government regulations;•the consumption pattern of industrial consumers, electricity generators and residential users;•weather can impact thermal coal demand (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles anddepressed the demand for thermal coal);•the price and availability of alternative fuels for electricity generation, especially natural gas (for example, abundant natural gas supplies at pricesaveraging less than $3/MMbtu during 2012 depressed the demand for thermal coal as natural gas fired electricity generation market shareincreased from approximately 25% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 42% in 2011 to 37% in 2012);and•increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, anintermediate product produced from metallurgical coal, decreases the demand for metallurgical coal.Decreased demand and extended or substantial price declines for coal adversely affect our operating results for future periods and our ability to generatecash flows necessary to improve productivity and expand operations. For example, in 2012 domestic and global economic deterioration, unusually warmwinter weather and abundant cheap natural gas decreased demand for our coal as well as decreased the average sales price for our metallurgical coal andresulted in our coal revenues and earnings before income taxes significantly declining from 2011. In 2013, our average sales price per ton of low volatilemetallurgical coal fell by approximately 34% due to oversupply which was particularly acute in the international market.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.30During the year ended December 31, 2013, approximately 70% of the coal CONSOL Energy produced from continued operations was sold under long-term contracts (contracts with terms of one year or more). If a substantial portion of CONSOL Energy's long-term contracts are modified or terminated or ifforce 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 levelof profitability. If existing customers do not honor current contract commitments, our revenue would be adversely affected. The profitability of our long-termcoal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our productioncosts and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costsmay reduce our profit margins. In addition, in periods of declining market prices, provisions in our long-term coal contracts for adjustment or renegotiation ofprices 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-termagreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, and long-term contracts maynot contribute to our profitability.The loss of, or significant reduction in, purchases by our largest coal customers could adversely affect our revenues.For the year ended December 31, 2013, we derived over 10% of our total revenues from sales to two coal customers individually and more than 35% ofour total revenue from sales to our four largest coal and gas customers. At December 31, 2013, we had approximately twenty-four coal supply agreements withthese customers that expire at various times from 2014 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 customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal tothem 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 natural gas and coal sold and delivered depends on the continued creditworthiness of our customers. Some powerplant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $200 millionaccounts receivable securitization program and our business could be adversely affected. In addition, if customers refuse to accept shipments of our coal forwhich they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer'scontractual obligations are honored.Our gas business depends on gathering, processing and transportation facilities owned by others and the disruption of, capacity constraintsin, or proximity to pipeline systems could limit sales of our natural gas. Similarly, the availability and reliability of transportation facilities andfluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.We gather, process and transport our gas to market by utilizing pipelines and facilities owned by others. If pipeline or facility capacity is limited, or ifpipeline or facility capacity is unexpectedly disrupted, our gas sales and/or sales of natural gas liquids could be limited, reducing our profitability. If wecannot access processing pipeline transportation facilities, we may have to reduce our production of gas or vent our produced gas to the atmosphere because wedo not have facilities to store excess inventory. If our sales of gas or natural gas liquids 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. 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, or other events could temporarily impair our ability to supply coal to customers andadversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is acritical factor in a customer's purchasing decision. Increases in transportation costs could make our coal less competitive.Competition within the natural gas and coal 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 natural gas and coal products, which could impair ourprofitability.31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.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 and competition. Increases incoal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. If overcapacity results, prices couldfall or we may not be able to sell our coal, which would reduce revenue.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 domestic coal sales and adversely affectour results of operations.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. Recent EPA rulemaking proceedings requiring additional reductions in permissible emission levels of impurities by coal-fired plants willlikely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in thefuture. Examples are (i) adoption of the Cross-State Air Pollution Rule (CASPR) in 2011 (to be effective January 1, 2012, but currently subject to a stayordering the agency to continue to enforce the Clean Air Interstate Rule promulgated in 2005 until a viable replacement to the cross-state regulation could beissued, with an appeal of CASPR currently pending before the U.S. Supreme Court); and (ii) adoption in 2012 of the Utility Maximum Control Technology(UMACT) rule in 2012, which included more stringent new source performance standards (NSPS) for particulate matter (PM), SO 2 and NO X, and theMercury and Air Toxics Standards (MATS) rule which set new mercury and air toxic standards (both of which were reconsidered and reissued with slightlyless stringent limits in 2013).Another source of uncertainty is the consideration of regulation of coal ash disposal by the EPA. In May 2010, the EPA proposed new approaches forthe regulation of Coal Combustion Residuals from electric generating facilities. The EPA is re-evaluating its August 1993 and May 2000 Bevill determinationsthat currently provide exemptions from the definition of hazardous wastes for certain materials. In October 2013, the U.S. District Court for the District ofColumbia ordered the EPA to publish proposed coal ash facility regulations under the non-hazardous provisions of the Resource Conservation and RecoveryAct. The EPA proposed regulations are not yet published.Apart from actual and potential regulation of emissions and solid wastes from coal-fired plants, state and federal mandates for increased use ofelectricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricitysuppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform,national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhancethe economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by domesticelectric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energysources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.32Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for natural gasand coal and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our natural gas and coalassets.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 natural gas and coal we produce, results in the creation of carbon dioxide emissions intothe atmosphere by natural gas and coal end-users, such as coal-fired electric power generation plants. Numerous proposals have been made and are likely tocontinue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states havealready adopted measures requiring reduction of GHGs within state boundaries. Internationally, the Kyoto Protocol, which set binding emission targets fordeveloped countries (but has not been ratified by the United States, and Canada officially withdrew from its Kyoto commitment in 2012) was nominallyextended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. The EPA has elected to regulateGHGs under the Clean Air Act. On January 8, 2014, EPA re-proposed NSPS for CO2 for new fossil fuel fired power plants and rescinded the rules that wereproposed on April 12, 2012. These proposed rules will also require CCS for new coal fired power plants.Apart from governmental regulation, on February 4, 2008, three of Wall Street's largest investment banks announced that they had adopted climatechange guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make itmore difficult for utilities to obtain financing for coal-fired plants.Adoption of comprehensive legislation or regulation focusing on GHGs emission reductions for the United States or other countries where we sell coal,or the inability of utilities to obtain financing in connection with coal-fired plants, it may make it more costly to operate fossil fuel fired (especially coal-fired)electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation orlegislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing thedemand for natural gas. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in thebuilding 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.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 natural gas and coal mining 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 natural gas and coal operations are also subject to hazards andany losses or liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.Our exploration for and production of natural gas involves numerous operating risks. The cost of drilling, completing and operating our shale gaswells, 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:33•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.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:•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.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 gas or coal 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 gas and coal 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 or34on satisfactory terms, and we may experience shortages of, or increases in the costs of, drilling equipment, crews and associated supplies, equipment andfield services in the future. We utilize third-party contractors to provide land acquisition and related services to support our land operational needs for both gasand coal segments. We also use third party contractors to provide construction and specialized services to our mining operations. A decrease in the availabilityof field services or equipment and supplies, an increase in the prices charged for field services, equipment and supplies, or the failure of third partycontractors to provide quality field services to us, could decrease our gas and coal production, increase our costs of gas and coal production, and decrease ouranticipated 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 drilling and mining 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.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. Delays or denials of gas permits could reduce our production, cash flows 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 other types of surface mining operations on variousgrounds. The most recent challenges have focused on the adequacy of the U.S Army Corps of Engineers analysis of impacts to streams and the adequacy ofmitigation plans to compensate for stream impacts resulting from valley fill permits required for mountaintop mining. These challenges have also enhanced theEPA's oversight and involvement in the review of permits by state regulatory authorities. In 2007, the U.S. District Court for the Southern District of WestVirginia found other operators' permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversedthat decision, finding that the permits were adequate. Nevertheless, the EPA's objections and an enhanced review process that was being implemented under afederal multi-agency memorandum of understanding effectively held up the issuance of permits for all types of mining operations that require Clean Water ActSection 402 discharge permits and Section 404 dredge and fill permits, including surface facilities for underground mines. The EPA's enhanced review processwas invalidated in October 2011, in part because the EPA failed to follow public notice and rulemaking requirements, and on July 31, 2012, the federalDistrict Court for the District of Columbia struck down the EPA's “guidance memorandum” for coal-related water permitting actions in which the EPArecommended permits include limits on specific conductivity which currently neither the EPA nor the states have a standard. However, normal permitting hasnot yet resumed. Also, the EPA may elect to seek to adopt regulations to codify its enhanced review process. CONSOL Energy's surface and undergroundoperations have been impacted to a limited extent to date, but a permit for a new mine was impacted which resulted in the issuance of a Worker Adjustmentand Retraining Notification (WARN) which affected some 145 employees on October 30, 2012. CONSOL Energy was able, in this instance, to redeploy theseemployees to work at another adjacent coal mine property for which a permit was already issued. However, the permit for the new mine still has not beenissued and there is no assurance that CONSOL Energy would be able to re-deploy its employees under future similar circumstances. In addition, the length oftime needed to bring a new mine into production has increased by several years because of the increased time required to obtain necessary permits. Thesedelays 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 othersthat govern our business may increase our costs of doing business for coal and may restrict our coal operations.We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authoritiesrelating to protection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the managementand disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, threatened and endangered plantand wildlife protection,35reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines,remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with theserequirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position.In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws. Any additional laws,regulations and other legal requirements enacted or adopted by federal, state and local authorities, as well as foreign authorities or new interpretations of existinglegal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations and competitive position. TheClean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits and bring citizen suits to make coal mining moreexpensive. In addition, CONSOL Energy may incur costs associated with the investigation and remediation of environmental contamination under the federalComprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and has been named as a potentiallyresponsible party at Superfund sites in the past.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 natural gas, and may restrict our gas operations.Regulations applicable to the gas industry are under constant review for amendment or expansion at the federal and state level. Any future changes mayaffect, among other things, the pricing or marketing of gas production. For example, hydraulic fracturing is an important and common practice that is used tostimulate production of hydrocarbons, particularly natural gas, from tight formations such as Marcellus Shale. The process involves the injection of water,sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oiland gas commissions. Hydraulic fracturing is currently exempt from regulation under the federal Safe Drinking Water Act, except for hydraulic fracturingusing diesel fuel. The disposal of produced water, drilling fluids and other wastes in underground injection disposal wells is regulated by the EPA under thefederal Safe Drinking Water Act or by the states under counterpart state laws and regulations. The imposition of new environmental initiatives and regulationscould include restrictions on our ability to conduct hydraulic fracturing operations or to dispose of waste resulting from such operations. The EPA hascommenced a study of the potential environmental impacts of hydraulic fracturing activities with a final report to be issued in 2014. Other federal agencies arealso examining hydraulic fracturing, including the U.S. Department of Energy (DOE), the U.S. Government Accountability Office and the Department of theInterior. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating tohydraulic fracturing in certain circumstances. If hydraulic fracturing is regulated at the federal, state or local level, our fracturing activities could becomesubject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs.Additionally, some states have begun to adopt more stringent regulation and oversight of natural gas gathering lines than is currently required by federalstandards. Pennsylvania, under Act 127, authorized the Public Utility Commission (PUC) oversight of Class I gathering lines, as well as requiring standardsand fees associated with Class II and Class III pipelines. The state of Ohio also moved to regulate natural gas gathering lines in a similar manner pursuant toOhio Senate Bill 315 (SB315). SB315 expanded the PUC's authority over rural natural gas gathering lines. These changes in interpretation and regulationaffect CONSOL Energy's midstream activities, requiring changes in reporting as well as increased costs.Further, some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed a temporarymoratorium on drilling operations using hydraulic fracturing until further study of the potential for environmental and human health impacts by the EPA orthe relevant agencies are completed. Also, a few municipalities in Colorado have adopted ordinances to ban hydraulic fracturing. No assurance can be given asto whether or not similar measures might be considered or implemented in jurisdictions in which our gas properties are located. If new laws or regulations thatsignificantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states in which we operate, such legal requirements couldmake it more difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commerciallyviable. New laws or regulations could also cause delays or interruptions or terminations of operations, the extent of which cannot be predicted, and couldreduce 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 couldhave a material adverse effect on our results of operations 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 from36the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas economically and in commercialquantities could be impaired.As part of our drilling and production in shale formations, we use hydraulic fracturing processes. Thus, we need access to adequate sources of water touse in our shale operations. Further, we must remove and dispose of the portion of the water that we use to fracture our shale gas wells that flows back to thewell-bore as well as drilling fluids and other wastes associated with the exploration, development or production of natural gas. In addition, in our CBM drillingand production, coal seams frequently contain water that must be removed and disposed of in order for the gas to detach from the coal and flow to the wellbore. Our inability to locate sufficient amounts of water with respect to our shale operations, or the inability to dispose of or recycle water and other wastesused in our shale and our CBM operations, could adversely impact our operations. For example, in Ohio, underground injection of gas well production fluidswas temporarily suspended for underground injection disposal wells near Youngstown while regulatory authorities investigated whether injection of wastewaterinto the wells was causing low category earthquakes 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 shutdown based on safety considerations. A mine could be shutdown 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 shutdown 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. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources,such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some ofour impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments wereto fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. Our coal refuseareas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmentaland safety standards.In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that37without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. CONSOL Energy has severaloperations with selenium discharges. CONSOL Energy and other coal companies are working to expeditiously develop cost effective means to remove seleniumfrom mine water. If such technology or processes are not developed promptly, the only available effective treatment technologies are expensive to construct andoperate which will increase coal production costs.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. An example of this is Naturally Occurring RadioactiveMaterial (NORM) or Technologically-Enhanced, Naturally Occurring Radioactive Material (TENORM). NORM or TENORM is produced when activitiessuch as deep drilling concentrate or expose radioactive materials that occur naturally in ores, soils, water, or other natural materials. State and federal agenciesare examining the possibility for worker exposure or associated environmental hazards due to processing and disposal of wastes containing NORM orTENORM. CONSOL Energy's operations could be affected if there is a hazard associated with NORM/TENORM or if it were to be regulated in such a wayas to require expensive treatment and disposal options.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 $601 million at December 31, 2013. 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 was underfunded, resultingin a citizen suit before the U.S. District Court in West Virginia. In an effort to settle the issue in 2012, the WV legislature authorized an increase in the per tonfee levied on coal production to make up the shortfall. There remains the possibility that WV may move to full cost bonding in the future which could causeindividual mining companies and/or surety companies to exceed bonding capacity and would result in the need to post cash bonds or letters of credit whichwould reduce operating capital. Pennsylvania is expanding its full cost bonding program to cover all coal mine bonding, further increasing the amount ofsurety bonds CONSOL Energy must seek in order to permit its mining activities.CONSOL Energy faces uncertainties in estimating our economically recoverable gas and coal reserves, and inaccuracies in our estimatescould result in lower than expected revenues, higher than expected costs and decreased profitability.Natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gas prices,production levels, and operating and development costs. As a result, estimated quantities of proved gas reserves and projections of future production rates andthe timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results ofactual drilling, testing and production. Also, we make certain assumptions regarding natural gas prices, production levels, and operating and developmentcosts that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our gas reserves, theeconomically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of gas reserves based on risk ofrecovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as describedabove, often result in the actual quantities of gas we ultimately recover being different from reserve estimates. The present value of future net cash flows fromour proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future netcash flows from our proved gas reserves on historical average prices and costs. However, actual future net cash flows from our gas and oil properties also willbe affected by factors such as:38•geological conditions;•changes in governmental regulations and taxation;•the amount and timing of actual production;•assumptions governing future prices;•future operating costs; and•capital costs of drilling, completion and gathering assets.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. If natural gas prices decline by $0.10 per Mcf, then the pre-tax present value using a 10%discount rate of our proved gas reserves as of December 31, 2013 would decrease from $2.8 billion to $2.6 billion.Similarly, there are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyondour control. 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.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 gas and coal 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.Defects may exist in our chain of title for our gas estate and we have not done a thorough chain of title examination of our gas estate. Wemay incur additional costs and delays to produce gas and coal because we have to acquire additional property rights to perfect our title to gasor coal rights. If we fail to acquire additional property rights to perfect our title to gas or coal rights, we may have to reduce our estimatedreserves.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. When we perform a thorough chain of title examination, we may discover material defects in our title which would require us toacquire additional property rights. We may incur substantial costs to acquire these additional property rights. In addition, the acquisition of the necessaryrights may not be feasible in some cases. Our discovering title defects which we are unable to cure may adversely impact our ability to develop those propertiesand we may have to reduce our estimated gas reserves including our proved undeveloped reserves.Some states (West Virginia and Virginia) permit us to produce coalbed methane gas without perfected ownership under an administrative process knownas “pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, wemay have to pay royalties to produce coalbed methane gas on39acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affectedareas.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. If we cannot cure these defects, we may have to reduce ourcoal reserves.Our subsidiaries, primarily Fairmont Supply Company, are co-defendants 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 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, 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. Past payments by Fairmont with respect to asbestoscases have not been material, however, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material tothe financial position, 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 three pending purported class action lawsuits dealing with claimants’entitlement to, and accounting for, gas royalties. There is the potential that the costs of defending litigation in an individual matter or the aggregation of manymatters could have an adverse effect on our cash flows, results of operations or financial position. See Note 24-Commitments and Contingent Liabilities in theNotes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.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, 2013, the current and non-current portions of these obligations included:•postretirement medical and life insurance ($1.0 billion);•coal workers' black lung benefits ($121.2 million);•salaried retirement benefits ($43.8 million); and•workers' compensation ($85.1 million). 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 unfunded. 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.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 CONSOL40Energy. Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Terminations Benefits requires that if the lump-sumdistributions made for a plan year exceed the total of the service cost and interest cost for the plan year, CONSOL Energy would need to recognize for thatyear's results of operations an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in thatyear. If the settlement is triggered in future periods, it may be material to operating results.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. We also continually seek to grow our business by adding and developing gas andcoal reserves through acquisitions and by expanding the production at existing mines and existing gas operations. If we are unable to successfully integrate thecompanies, businesses or properties we acquire, we may fail to realize the expected benefits of the acquisition and our profitability may decline and we couldexperience a material adverse effect on our business, financial condition, or results of operations. Acquisitions, mine expansion and gas operation expansioninvolve various 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 our Marcellus shale oil and gas assets to Noble Energy and a 50% undivided interest in our Utica shale acres in Ohio to Hess. Thefollowing 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. 41•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.•Approximately $1.9 billion of consideration that we expect to receive from Noble Energy depends upon Noble Energy paying a portion of ourshare of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess OhioDevelopments, LLC (Hess) in which approximately $335 million of consideration that we expect to receive from Hess is dependent upon Hesspaying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilledand developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third partyobligations is outside our control. The inability or failure of a joint venturer to pay its portion of development costs, including our carried costsduring the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights todevelop the oil and gas properties held by that joint venture.•Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per 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.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, 2013, our total indebtedness was approximately $3.175 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 Maryland Economic Development Corporation Port Facilities Refunding Revenue Bonds (MEDCO) 5.75%revenue bonds due September 2025, $56 million of capitalized leases due through 2021, and $16 million of miscellaneous debt. The degree to which we areleveraged 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 gas andcoal 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 facilities and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes limit the incurrence ofadditional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreements and the indentures governing our 8.00%,8.25% and 6.375% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreements, we mustcomply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, and a maximum senior secured leverage ratio, asdefined. Our senior secured credit agreements and the indentures governing our 8.00%, 8.25% and 6.375% senior unsecured notes impose a number ofrestrictions upon us, such as restrictions on granting liens on our assets, making investments, paying dividends, selling assets and engaging in acquisitions.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.42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, 2013, 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 January 21, 2014, we had hedges on approximately 129.3 Bcf of our 2014 natural gas production, 78.6 Bcf of our 2015 natural gasproduction, and 71.3 Bcf of our 2016 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing thebenefits of price increases above the levels of the hedges. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may bemore adversely affected by changes in natural gas prices than our competitors who engage in hedging arrangements to a greater extent than we do.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.Changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause ourfinancial position and profitability to deteriorate.The passage of legislation or any other similar changes in U.S. federal income tax law could eliminate or postpone certain tax deductions that arecurrently available with respect to natural gas, oil or coal exploration and development. Any such change could negatively affect our financial condition andresults of operations.In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania, where a substantial portion of our acreagein the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. Thefee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average New YorkMercantile Exchange's natural gas prices from the last day of each month. The estimated total fees per well based on today's current natural gas price is $310thousand over the 15 year period. The passage of this legislation increases the financial burden on our operations in the Marcellus Shale.Several portions of Act 13 were overturned by the Pennsylvania Supreme Court in December 2013, including the portion that addressed municipaluniformity, and the Company is assessing the exact reach and scope of that decision. In the meantime, disparities in municipal rules for industry operationsare likely. Moreover, the Pennsylvania Supreme Court’s ruling may affect the annual impact fee on unconventional gas wells, as the fee was tied to municipal-ordinance uniformity.43Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure toappropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition.Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, weconsidered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions,exploratory activity, coal development, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding thedeterminations made in the development of our business plan, business opportunities not previously identified periodically come to our attention, includingpossible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raisingopportunities and the use of our other resources in furtherance of our business strategies, our financial condition and future growth may be adversely affected.Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to thosechanges may limit our ability to achieve our objectives.Any failure by Murray Energy to satisfy the liabilities it assumed from us, as well as to perform its obligations under various agreementswhose performance by Murray Energy we guaranteed to satisfy obligations, or under various agreements with us could materially increaseour liabilities and materially adversely affect our results of operations, financial position and cash flows.Murray Energy and its subsidiaries (Murray Energy) acquired approximately $2.4 billion of liabilities which had been reflected on our books. Inaddition to these assumed liabilities, (i) Murray Energy acquired our obligations under the multi-employer defined benefit pension plan for United MineWorkers of America (1974 Pension Plan), (ii) we guaranteed performance by Murray Energy under various West Virginia and Pennsylvania operational suretybonds and workers compensation obligations, under various equipment leases and to reclaim an impoundment site, and (iii) we leased or subleased variousmining equipment to Murray Energy and we guaranteed performance by Murray Energy of certain coal supply agreements that Murray Energy acquired in thetransaction. Our maximum estimated exposure under our Murray Energy guarantees as of December 31, 2013 was approximately $404 million. The leases andsubleases we entered into with Murray Energy relate to approximately $200 million of equipment. Murray Energy also acquired retiree medical liabilities underthe Coal Industry Retiree Health Benefits Act of 1992, for which Murray Energy is primarily liable, but CONSOL Energy remains secondarily liable. OnNovember 12, 2013 in connection with the transaction, Moody’s assigned Murray Energy a family credit rating of B3 (speculative and subject to high creditrisk) and its secured second lien notes due 2021 of Caa1(poor standing and subject to very high credit risk). Any failure by Murray Energy to satisfy theseassumed liabilities or perform under these agreements could result in substantial claims against us by third parties and materially adversely affect our resultsof operations, financial position and cash flows. In addition, we will regularly evaluate the likelihood of default by Murray Energy under the guarantees wehave provided. The results of the evaluation may materially impact our results of operations. If Murray Energy defaults under the obligations we guarantee ourcash flows may also be materially impacted.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 sixth 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 annual report.PART II44ITEM 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, 2013 Quarter Ended March 31, 2013 $34.79 $29.91 $— Quarter Ended June 30, 2013 $35.79 $27.10 $0.125 Quarter Ended September 30, 2013 $35.56 $26.51 $0.125 Quarter Ended December 31, 2013 $38.42 $33.99 $0.125Year Period Ended December 31, 2012 Quarter Ended March 31, 2012 $39.37 $31.72 $0.125 Quarter Ended June 30, 2012 $35.15 $26.80 $0.125 Quarter Ended September 30, 2012 $33.79 $27.83 $0.125 Quarter Ended December 31, 2012 $36.60 $29.71 $0.250As of December 31, 2013, there were 162 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, Alpha Natural Resources Inc., Anadarko Petroleum Corp., Apache Corp., Arch Coal Inc., Chesapeake Energy Corp., Devon EnergyCorp., EOG Resources Inc., Newfield Exploration Co., Noble Energy Inc., Peabody Energy Corp., Southwestern Energy Co., QEP Resources Inc., and WPXEnergy, Inc. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2008. Thegraph also assumes that all dividends were reinvested and that the investments were held through December 31, 2013. 2008 2009 2010 2011 2012 2013CONSOL Energy Inc. 100.0 175.6 173.3 132.1 117.8 141.0Peer Group 100.0 149.0 167.3 140.2 131.4 151.2S&P 500 Stock Index 100.0 63.4 79.8 91.7 104.0 134.8Cumulative Total Shareholder Return Among CONSOL Energy Inc., Peer Group and S&P 500 Stock Index45The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).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 5.14 to 1.00 and our availability was approximately$793 million at December 31, 2013. 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, 2013.See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating toCONSOL Energy's equity compensation plans.46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, 2013, 2012, 2011, 2010 and 2009 are derived from ouraudited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2013presentation. 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. For the Years Ended December 31, 2013 2012 2011 2010 2009Operating revenues from Continuing Operations $3,120,722 $3,282,350 $4,237,913 $3,559,511 $3,202,549Income from Continuing Operations $79,264 $317,959 $681,675 $315,240 $515,700Net Income Attributable to CONSOL Energy Inc.Shareholders $660,442 $388,470 $632,497 $346,779 $539,717Earnings per share: Basic: Income from Continuing Operations $0.35 $1.40 $3.01 $1.41 $2.70Income from Discontinued Operations 2.54 0.31 (0.22) 0.20 0.29Net Income $2.89 $1.71 $2.79 $1.61 $2.99Dilutive: Income from Continuing Operations $.35 $1.39 $2.98 $1.40 $2.67Income from Discontinued Operations 2.52 0.31 (0.22) 0.20 0.28Net Income $2.87 $1.70 $2.76 $1.60 $2.95 Assets from Continuing Operations $11,393,667 $10,383,343 $9,952,077 $9,543,457 $5,281,010Assets from Discontinued Operations — 2,614,251 2,573,623 2,527,153 2,494,391Total assets $11,393,667 $12,997,594 $12,525,700 $12,070,610 $7,775,401 Long-term debt from Continuing Operations (including currentportion) $3,175,014 $3,185,497 $3,196,455 $3,209,101 $465,975Long-term debt from Discontinued Operations (includingcurrent portion) — 2,574 1,659 1,820 2,327Total Long-term debt (including current portion) $3,175,014 $3,188,071 $3,198,114 $3,210,921 $468,302Cash dividends declared per share of common stock $0.375 $0.625 $0.425 $0.400 $0.400See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of anadjustment to operating revenues for all periods and other matters that affect the comparability of the selected financial data as well as uncertainties that mightaffect the Company’s future financial condition.47OTHER OPERATING DATA(unaudited) Years Ended December 31, 2013 2012 2011 2010 2009Gas: Net sales volumes produced (in billion cubic feet) 172.4 156.3 153.5 127.9 94.4Average sales price ($ per Mcfe)(A) $4.30 $4.22 $4.90 $5.83 $6.68Average cost ($ per Mcfe) $3.51 $3.37 $3.53 $3.54 $3.15Proved reserves (in Bcfe) (B) 5,731 3,993 3,480 3,732 1,911 Coal: Tons sold from continuing operations (in thousands)(C) 28,776 27,612 32,090 32,280 32,185Tons produced from continuing operations (in thousands) 28,476 27,178 31,721 31,895 32,987Average sales price of tons produced ($ per ton produced) $69.34 $77.75 $90.10 $73.31 $66.71Average Cost of Goods Sold ($ per ton produced) $50.78 $53.98 $51.88 $44.37 $41.76Recoverable coal reserves (tons in millions)(D) 3,032 4,229 4,314 4,229 4,350Number of active mining complexes (at end of period) 4 5 7 7 6____________(A)Represents average net sales price including the effect of derivative transactions.(B)Represents proved developed and undeveloped gas reserves at period end.(C)Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the followingamount from third parties: 0.6 million tons, 0.5 million tons, 0.6 million tons, 0.2 million tons, and 0.3 million tons for the years ended December 31,2013, 2012, 2011, 2010 and 2009, respectively.(D)Represents proven and probable coal reserves at period end, excluding equity affiliates.48ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of OperationsGeneral2013 Highlights•Record total gas production of 172.4 Bcfe in 2013, 10% higher than 2012.•Record Marcellus Shale production of 57.8 Bcfe in 2013, 58% higher than 2012.•Completed a lease with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny CountyAirport, for the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of theMarcellus Shale play. An up-front bonus payment of $46.3 million was paid at closing. Noble Energy, our joint venture partner, acquired50% of the acres and accordingly, reimbursed CONSOL Energy for 50% of the associated costs. Approximately 7.6% of the bonus paymentwas placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres thathave potentially defective title. To date, less than 1% of this amount has been released from escrow. We must spud a well by February 21,2015 and proceed with due diligence to complete the well or the lease terminates and the bonus is foregone. •Entered into a farm-in agreement for approximately 90 thousand additional Marcellus Shale acres in West Virginia. Consideration of up to$190 million will be paid by CONSOL Energy in two installments: (i) 50% was paid at closing and (ii) the balance due over time as the acresare drilled. Closing occurred on December 5, 2013. Noble Energy, our Marcellus Shale joint venture partner, acquired a 50% interest in theacres and accordingly, will reimburse CONSOL Energy for 50% of the associated costs.•Completed the sale of Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of CONSOL Energy'slongwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). The CCC mines sold were McElroyMine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 26.7 milliontons of thermal coal in 2013 and 28.8 million tons of thermal coal in 2012. Murray Energy acquired approximately 1.1 billion tons ofPittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations were included in the transaction. CONSOL Energy received$850 million in cash as a result of the transaction. CONSOL Energy retained an overriding royalty interest in certain reserves sold in thetransaction that included minimum royalty payments of $42 million. Additionally, Murray Energy acquired approximately $1.9 billion ofother postretirement benefit plan liabilities, $100 million of workers compensation liabilities, $50 million of coal workers’ pneumoconiosisliabilities, $10 million of long term disability liabilities, $155 million of environmental liabilities and CONSOL Energy’s UMWA 1974Pension Trust Obligations. The pre-tax financial gain resulting from the transaction was $1,035 million.•In conjunction with the sale of CCC and certain of its subsidiaries, CONSOL Energy realigned its dividend policy to reflect the company’sincreased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, or a 2014 annual rateof $0.25 per share, beginning with the first quarter of 2014.2014 Expectations:•Our 2014 annual gas production is expected to be between 215 - 235 Bcfe with annual production growth of 30% for 2015 and 2016.•Our 2014 gas capital investment is expected to be $1,110 million.•Our 2014 coal production is expected to be between 30.1 - 32.1 million tons.•Our 2014 coal capital investment is expected to be $390 million.•Pension settlement accounting may occur in 2014 related to staff reduction that occured in relation to the sale of CCC and certain subsidiaries.•BMX Mine is expected to begin longwall mining during the first quarter of 2014.Several significant transactions occurred in the year ended December 31, 2013. These events include the following:Continuing Operations:•In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada.The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceedsfor the sale were $24.7 million. The transaction resulted in a $15.3 million pre-tax gain on the sale of assets.49•On June 24, 2013, CONSOL Energy closed the sale of the Potomac coal reserves located in Grant and Tucker Counties in West Virginia. Cashproceeds from the sale were $25.0 million. The transaction resulted in a $24.7 million pre-tax gain on the sale of assets.•Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company'squalified and non-qualified salary retirement pension plans exceeding the annual projected service and interest costs of the plans. The pensionsettlement resulted in a $39.5 million pre-tax expense adjustment. Many of the lump sum payments in the year ended December 31, 2013 were paidto employees who elected to retire under the 2012 Voluntary Severance Incentive Plan.•A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the year ended December 31, 2013. As a result of theCompany's review of the title defects, asserted by its joint venture partner Noble Energy, and working in collaboration with Noble, CONSOLEnergy has conceded defects on acreage with a value of $23.1 million. See Note 11- Property, Plant and Equipment, in the Notes to the AuditedConsolidated Financial Statements included in this Form 10-K for additional details.•In the year ended December 31, 2013, an agreement was reached for resolution of the class actions brought by shareholders of CNX Gas alleging thatthe price paid by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 pershare in May 2010 was not fair. The total settlement provided for a payment to the plaintiffs of $42.7 million, of which the CONSOL Energy’sportion was $19.2 million. See Note 24 - Commitments and Contingencies, in the Notes to the Audited Consolidated Financial Statements includedin this Form 10-K for additional details.Discontinued Operations:•On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County,Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified andcontainment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. Thisevent resulted in a pre-tax expense of $34.3 million in the year ended December 31, 2013.•Severance and related costs of $9.5 million pre-tax expense related to the change in control of the 5 coal mines and the reduction of supportingadministrative staff was reflected in the 2013 financial results.•Settlement and curtailment gains totaling $1.6 billion were recognized related to the company’s obligations under the Other Postretirement Benefits,Workers’ Compensation, Pension, Coal Workers’ Pneumoconiosis, and Long-Term Disability plans as a result of the sale to Murray Energy.50Results of OperationsYear Ended December 31, 2013 Compared with Year Ended December 31, 2012Net Income Attributable to CONSOL Energy ShareholdersCONSOL Energy reported net income attributable to CONSOL Energy shareholders of $660 million, or $2.87 per diluted share, for the year endedDecember 31, 2013. Net income attributable to CONSOL Energy shareholders was $388 million, or $1.70 per diluted share, for the year ended December 31,2012. Included in net income is income from continuing operations of $79 million, or $0.35 per diluted share, for the year ended December 31, 2013. Incomefrom continuing operations was $318 million, or $1.39 per diluted share, for the year ended December 31, 2012. Also included in net income is income fromdiscontinued operations of $580 million, or $2.52 per diluted share, for the year ended December 31, 2013. Income from discontinued operations was $70million, or $0.31 per diluted share, for the year ended December 31, 2012.The total gas division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total gas division contributed a loss of $2million before income tax for the year ended December 31, 2013 compared to $39 million of earnings before income tax for the year ended December 31, 2012.Total gas production was 172.4 Bcfe for the year ended December 31, 2013 compared to 156.3 Bcfe for the year ended December 31, 2012.The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production andsales portfolio: For the Years Ended December 31, in thousands (unless noted) 2013 2012 Variance PercentChangeLIQUIDS NGLs: Sales Volume (MMcfe) 2,628 610 2,018 330.8 %Sales Volume (Mbbls) 438 102 336 329.4 %Gross Price ($/Bbl) $53.76 $52.32 $1.44 2.8 %Gross Revenue $23,541 $5,314 $18,227 343.0 % Oil: Sales Volume (MMcfe) 634 600 34 5.7 %Sales Volume (Mbbls) 106 100 6 6.0 %Gross Price ($/Bbl) $89.58 $92.58 $(3.00) (3.2)%Gross Revenue $9,469 $9,252 $217 2.3 % Condensate: Sales Volume (MMcfe) 381 63 318 504.8 %Sales Volume (Mbbls) 64 11 53 481.8 %Gross Price ($/Bbl) $81.06 $78.84 $2.22 2.8 %Gross Revenue $5,158 $823 $4,335 526.7 % GAS Sales Volume (MMcf) 168,737 155,052 13,685 8.8 %Sales Price ($/Mcf) $3.71 $2.94 $0.77 26.2 %Hedging Impact ($/Mcf) $0.45 $1.22 $(0.77) (63.1)%Gross Revenue $702,700 $645,053 $57,647 8.9 % 51The average sales price and average costs for all active gas operations were as follows: For the Years Ended December 31, 2013 2012 Variance PercentChangeAverage Sales Price (per Mcfe)$4.30 $4.22 $0.08 1.9 %Average Costs (per Mcfe)3.51 3.37 0.14 4.2 %Margin$0.79 $0.85 $(0.06) (7.1)%Total gas division outside sales revenues were $741 million for the year ended December 31, 2013 compared to $659 million for the year endedDecember 31, 2012. The increase was primarily due to the 10.3% increase in total volumes sold, along with a 1.9% increase in average price per Mcfe. Theincrease in average sales price is the result of an increase in general market prices and the increase in sales of natural gas liquids and condensate. The increasewas offset, in part, by various gas swap transactions that occurred throughout both periods. The gas swap transactions qualify as financial cash flow hedgesthat exist parallel to the underlying physical transactions. These financial hedges represented approximately 84.3 Bcf of our produced gas sales volumes for theyear ended December 31, 2013 at an average price of $4.68 per Mcf. These financial hedges represented 76.9 Bcf of our produced gas sales volumes for theyear ended December 31, 2012 at an average price of $5.25 per Mcf.Changes in the average cost per Mcfe of gas sold were primarily related to the following items:•Gathering costs increased in the period-to-period comparison due to a $0.04 per Mcfe increase in processing fees associated with natural gas liquidsand a $0.10 per Mcfe increase in firm transportation costs.•Depreciation, depletion and amortization rates increased due to higher units-of-production for producing properties in the period to period comparisonoffset, in part, by additional volumes.•These increases were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling program. Fixedcosts are allocated over increased volumes, resulting in lower unit costs.The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed$337 million of earnings before income tax for the year ended December 31, 2013 compared to $592 million for the year ended December 31, 2012. The totalcoal division sold 28.8 million tons of coal produced from CONSOL Energy mines, for the year ended December 31, 2013 compared to 27.6 million tons forthe year ended December 31, 2012.The average sales price and average cost of goods sold per ton for continuing coal operations were as follows: For the Years Ended December 31, 2013 2012 Variance PercentChangeAverage Sales Price per ton sold$69.34 $77.75 $(8.41) (10.8)%Average Costs of Goods Sold per ton50.78 53.98 (3.20) (5.9)%Margin$18.56 $23.77 $(5.21) (21.9)%The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets. The coal division priced 7.9 million tons on theexport market at an average sales price of $72.27 per ton for the year ended December 31, 2013 compared to 7.5 million tons at an average price of $83.67 perton for the year ended December 31, 2012. All other tons were sold on the domestic market.Changes in the average cost of goods sold per ton were primarily related to the following items:•Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.•On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal fromboth the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled for approximatelythree weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period,which resulted in lower direct operating costs per ton produced.52•The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-periodcomparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall averagedirect operating costs per ton produced.•Direct services to operations are improved primarily due to a reduction in subsidence expenses related to the timing and nature of properties andstreams undermined as well as a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussedbelow under general and administrative costs.•Depreciation, depletion and amortization was improved primarily due to the idling of operations at the Fola Mining Complex in August 2012. Theimprovements were offset, in part, by higher costs in the 2013 period related to Bailey, Enlow Fork, and Buchanan Mines running for the full yearin 2013 compared to being idled at various times throughout 2012.•Average direct operating costs were impaired due to CONSOL Energy entering into a new longwall lease in 2013 at our Bailey Mine.•Costs were impaired in the current period due to the idling of the Buchanan Mine for various months throughout 2012. Although idled at timesduring 2012, the Buchanan Mine ran the continuous miners and worked on various projects which increased overall 2012 unit costs.The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the gas or coalsegment.General and Administrative costs for continuing operations are allocated between divisions (Coal, Gas, Other) based primarily on percentage of totalrevenue and percentage of total projected capital expenditures. General and Administrative costs are excluded from the coal and gas unit costs above. TotalGeneral and Administrative costs from continuing operations were made up of the following items: For the Years Ended December 31, 2013 2012 Variance PercentChangeContributions$7 $9 $(2) (22.2)%Employee Wages and Related Expenses33 35 (2) (5.7)%Advertising and Promotion4 4 — — %Consulting and Professional Services21 14 7 50.0 %Miscellaneous17 17 — — %Total Company General and Administrative Expenses$82 $79 $3 3.8 %Total Company General and Administrative Expenses changed due to the following:•Contributions decreased $2 million related to various transactions that occurred throughout both periods, none of which were individually material.•Employee wages and related expenses decreased $2 million primarily attributable to fewer employees as a result of the 2012 Voluntary SeveranceIncentive Plan, as previously discussed. There was also lower salary other post-employment benefit (OPEB) expenses in the period-to-periodcomparison related to changes in the discount rates and other assumptions.•Advertising and promotion remained consistent in the period-to-period comparison.•Consulting and professional services increased $7 million in the period-to-period comparison. Various legal proceedings accounted for $3 million ofthe increase and an additional $2 million was related to tax advisory services. The remaining increase was due to various other corporate initiatives,none of which were individually significant.•Miscellaneous general and administrative expenses remained consistent in the period-to-period comparison.Total Company long-term liabilities for continuing operations, such as 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 continuing operations expense related to our actuarial liabilities was $166 million for the year ended December 31,2013 compared to $148 million for the year ended December 31, 2012. The increase of $18 million for total CONSOL Energy continuing operations expensewas primarily due to required pension settlement accounting which resulted in $39 million of expense. Pension settlement expenses were required when lumpsum distributions made for the 2013 plan year exceeded the total of the service cost and interest cost for the 2013 plan year. The pension settlement was notallocated to individual operating segments and is therefore not included in unit costs presented for gas or coal. This was offset, in part, due to a modificationof the salaried post-employment benefit plan and an increase in the discount rate assumptions used to calculate expense for benefit plans at the53measurement date, which is December 31. See Note 16 - Pension and Other Post-Employment Benefit Plans and Note 17 - Coal Workers' Pneumoconiosis(CWP) and Workers' Compensation Net Periodic Benefit Costs in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K foradditional detail of the total Company expense increase.TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2013 compared to the year ended December 31, 2012:The gas segment had a loss before income tax of $2 million for the year ended December 31, 2013 compared to a earnings before income tax of $39million for the year ended December 31, 2012. For the Year Ended Difference to Year Ended December 31, 2013 December 31, 2012 Marcellus CBM ShallowOil andGas OtherGas TotalGas Marcellus CBM ShallowOil andGas OtherGas TotalGasSales: Produced$252 $336 $131 $19 $738 $118 $(42) $(4) $9 $81Related Party— 3 — — 3 — 1 — — 1Total Outside Sales252 339 131 19 741 118 (41) (4) 9 82Gas Royalty Interest— — — 63 63 — — — 13 13Purchased Gas— — — 7 7 — — — 4 4Other Income— — — 58 58 — — — 1 1Total Revenue and OtherIncome252 339 131 147 869 118 (41) (4) 27 100Lifting20 37 35 5 97 8 — (5) 3 6Ad Valorem,Severance, andOther Taxes9 9 10 1 29 5 (1) — (1) 3Gathering50 114 34 3 201 26 8 8 (2) 40Gas DirectAdministrative,Selling & Other26 8 10 5 49 9 (6) (3) 2 2Depreciation,Depletion andAmortization67 90 60 13 230 20 3 1 4 28General &Administration— — — 45 45 — — — 5 5Gas RoyaltyInterest— — — 53 53 — — — 14 14Purchased Gas— — — 5 5 — — — 2 2Exploration andOther Costs— — — 61 61 — — — 22 22Other CorporateExpenses— — — 92 92 — — — 15 15Interest Expense— — — 9 9 — — — 4 4Total Cost172 258 149 292 871 68 4 1 68 141Earnings (Loss) BeforeIncome Tax80 81 (18) (145) (2) 50 (45) (5) (41) (41)54MARCELLUS GAS SEGMENTThe Marcellus segment contributed $80 million to the total Company earnings before income tax for the year ended December 31, 2013 compared to $30million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangeMarcellus Gas Sales Volumes (Bcf)55.0 35.9 19.1 53.2 %NGLs Sales Volumes (Bcfe)*2.5 0.6 1.9 316.7 %Condensate Sales Volumes (Bcfe)*0.3 — 0.3 100.0 %Total Marcellus Gas Sales Volumes (Bcfe)*57.8 36.5 21.3 58.4 % Average Sales Price - Gas (Mcf)$3.77 $2.89 $0.88 30.4 %Hedging Impact - Gas (Mcf)$0.32 $0.69 $(0.37) (53.6)%Average Sales Price - NGLs (Mcfe)*$9.09 $8.68 $0.41 4.7 %Average Sales Price - Condensate (Mcfe)*$13.73 $13.54 $0.19 1.4 % Total Average Marcellus sales (per Mcfe)$4.35 $3.68 $0.67 18.2 %Average Marcellus lifting costs (per Mcfe)$0.35 $0.34 $0.01 2.9 %Average Marcellus ad valorem, severance, and other taxes (per Mcfe)$0.16 $0.12 $0.04 33.3 %Average Marcellus gathering costs (per Mcfe)$0.86 $0.67 $0.19 28.4 %Average Marcellus direct administrative, selling & costs (per Mcfe)$0.45 $0.46 $(0.01) (2.2)%Average Marcellus depreciation, depletion and amortization costs (per Mcfe)$1.16 $1.30 $(0.14) (10.8)% Total Average Marcellus costs (per Mcfe)$2.98 $2.89 $0.09 3.1 % Average Margin for Marcellus (per Mcfe)$1.37 $0.79 $0.58 73.4 %* NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and naturalgas,which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.The Marcellus segment sales revenues were $252 million for the year ended December 31, 2013 compared to $134 million for the year endedDecember 31, 2012. The $118 million increase is primarily due to a 58.4% increase in total volumes sold, and an 18.2% increase in total average sales pricesin the period-to-period comparison. The increase in sales volumes is primarily due to additional wells coming on-line from our on-going drilling program. Theincrease in Marcellus total average sales price was the result of the $0.88 per Mcf increase in gas market prices, along with a $0.16 per Mcf increase due to the2.2 Bcfe additional natural gas liquids and condensate sales volumes. The increase was offset, in part, by a $0.37 per Mcf decrease resulting from variousgas swap transactions that settled in the year ended December 31, 2013 compared to the 2012 period. These gas swap transactions qualify as financial cashflow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 21.6 Bcf of our produced Marcellusgas sales volumes for the year ended December 31, 2013 at an average price of $4.67 per Mcf. For the year ended December 31, 2012, these financial hedgesrepresented 12.4 Bcf at an average price of $4.99 per Mcf.Total costs for the Marcellus segment were $172 million for the year ended December 31, 2013 compared to $104 million for the year endedDecember 31, 2012. The increase in total dollars and unit costs for the Marcellus segment are due to the following items:•Marcellus lifting costs were $20 million for the year ended December 31, 2013 compared to $12 million for the year ended December 31, 2012. Theincrease primarily relates to an increase in sales volumes, along with an increase in salt water disposal costs, road maintenance costs, and well tending costs.The impact on average unit costs from these increases was offset by higher sales volumes.•Marcellus ad valorem, severance and other taxes were $9 million for the year ended December 31, 2013 compared to $4 million for the year endedDecember 31, 2012. The increase in total dollars and unit costs is primarily due to an increase in severance tax expense caused by higher average gas salesprices and the 58.4% increase in sales volumes during the current period.55•Marcellus gathering costs were $50 million for the year ended December 31, 2013 compared to $24 million for the year ended December 31, 2012.Total dollars increased due to an increase in processing fees associated with natural gas liquids, which resulted in a $0.12 per Mcfe increase in average unitcosts. Higher firm transportation costs also resulted in an increase on unit costs. The impact on average unit costs from these increases was offset, in party,by higher sales volumes.•Marcellus direct administrative, selling and other costs were $26 million for the year ended December 31, 2013 compared to $17 million for theyear ended December 31, 2012. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gas segmentsbased on a combination of production and employee counts. The increase in direct administrative, selling & other costs was primarily due to Marcellusvolumes representing a larger proportion of CONSOL Energy's total gas sales volumes. The impact on average unit costs from the increase in directadministrative costs was offset by higher sales volumes.•Depreciation, depletion and amortization costs were $67 million for the year ended December 31, 2013 compared to $47 million for the year endedDecember 31, 2012. There was approximately $66 million, or $1.14 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, 2013. There wasapproximately $44 million, or $1.24 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, 2012. There was approximately $1 million, or $0.02 perMcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the year endedDecember 31, 2013. There was $3 million, or $0.06 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment reflected ona straight line basis for the year ended December 31, 2012.COALBED METHANE (CBM) GAS SEGMENTThe CBM segment contributed $81 million to the total Company earnings before income tax for the year ended December 31, 2013 compared to $126million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangeCBM Gas Sales Volumes (Bcf)82.9 88.2 (5.3) (6.0)% Average Sales Price - Gas (Mcf)$3.69 $2.88 $0.81 28.1 %Hedging Impact - Gas (Mcf)$0.40 $1.44 $(1.04) (72.2)% Total Average CBM sales price (per Mcf)$4.09 $4.32 $(0.23) (5.3)%Average CBM lifting costs (per Mcf)$0.44 $0.42 $0.02 4.8 %Average CBM ad valorem, severance, and other taxes (per Mcf)$0.10 $0.12 $(0.02) (16.7)%Average CBM gathering costs (per Mcf)$1.37 $1.21 $0.16 13.2 %Average CBM direct administrative, selling & other costs (per Mcf)$0.10 $0.16 $(0.06) (37.5)%Average CBM depreciation, depletion and amortization costs (per Mcf)$1.10 $0.98 $0.12 12.2 % Total Average CBM costs (per Mcf)$3.11 $2.89 $0.22 7.6 % Average Margin for CBM (per Mcf)$0.98 $1.43 $(0.45) (31.5)%CBM sales revenues were $339 million in the year ended December 31, 2013 compared to $380 million for the year ended December 31, 2012. The $41million decrease was primarily due to a 6.0% decrease in total volumes sold and a 5.3% decrease in total average sales price per Mcf. CBM sales volumesdecreased 5.3 Bcf for the year ended December 31, 2013 compared to the 2012 period primarily due to normal well declines and fewer CBM wells being drilledin the 2013 period. Currently, the focus of the gas division is to develop its Marcellus and Utica acreage. The CBM total average sales price decreased $1.04due to various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to theunderlying physical transactions. Financial hedges represented approximately 48.3 Bcf of our produced CBM gas sales volumes for the year endedDecember 31, 2013 at an average price of $4.54 per Mcf. For the year ended December 31, 2012, these financial hedges represented 45.8 Bcf at an averageprice of $5.34 per Mcf. The decrease was offset, in part, by a $0.81 per Mcf increase in average gas market prices.56Total costs for the CBM segment were $258 million for the year ended December 31, 2013 compared to $254 million for the year ended December 31,2012. The increase in total dollars and unit costs for the CBM segment are due to the following items: •CBM lifting costs were $37 million for the year ended December 31, 2013 compared to $37 million for the year ended December 31, 2012. Thedecrease in total dollars was primarily due to lower road maintenance and lower contractor services in the period-to-period comparison. The increase in unitcosts was due to the decrease in gas sales volumes and was offset, in part, by the decrease in total costs.•CBM ad valorem, severance and other taxes were $9 million for the year ended December 31, 2013 compared to $10 million for the year endedDecember 31, 2012. The decrease of $1 million was primarily due to a reassement of our ad valorem taxes paid to Tazewell County, Virginia resulting in acurrent year refund. The decrease was offset, in part, by an increase in severance tax expense resulting from the increase in average sales price, without theimpact of hedging, as described above.•CBM gathering costs were $114 million for the year ended December 31, 2013 compared to $106 million for the year ended December 31, 2012.The increase in total dollars and average per unit costs was due to increased compression costs, increased power fees, and increased pipeline and roadmaintenance. Unit costs were also negatively impacted by the decrease in gas sales volumes.•CBM direct administrative, selling and other costs were $8 million for the year ended December 31, 2013 compared to $14 million for the yearended December 31, 2012. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments basedon a combination of production and employee counts. The decrease in direct administrative, selling & other costs was primarily due to reduced directadministrative labor and CBM volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. Improvements in unit costs wereoffset, in part, by the decrease in gas sales volumes. •Depreciation, depletion and amortization attributable to the CBM segment was $90 million for the year ended December 31, 2013 compared to $87million for the year ended December 31, 2012. There was approximately $62 million, or $0.77 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 31,2013. The production portion of depreciation, depletion and amortization was $60 million, or $0.67 per unit-of-production in the year ended December 31,2012. There was approximately $28 million, or $0.33 per Mcf of depreciation, depletion and amortization related to gathering and other equipment reflected ona straight line basis for the year ended December 31, 2013. The non-production related depreciation, depletion and amortization was $28 million, or $0.31 perMcf for the year ended December 31, 2012.57SHALLOW OIL AND GAS SEGMENTThe shallow oil and gas segment had a loss before income tax of $18 million for the year ended December 31, 2013 compared to a loss before income taxof $13 million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangeShallow Oil and Gas Sales Volumes (Bcf)27.5 28.7 (1.2) (4.2)%Oil Sales Volumes (Bcfe)*0.4 0.5 (0.1) (20.0)%Total Shallow Oil and Gas Sales Volumes (Bcfe)*27.9 29.2 (1.3) (4.5)% Average Sales Price - Gas (Mcf)$3.66 $3.12 $0.54 17.3 %Hedging Impact - Gas (Mcf)$0.89 $1.33 $(0.44) (33.1)%Average Sales Price - Oil (Mcfe)*$14.42 $15.65 $(1.23) (7.9)% Total Average Shallow Oil and Gas sales price (per Mcfe)$4.70 $4.64 $0.06 1.3 %Average Shallow Oil and Gas lifting costs (per Mcfe)$1.28 $1.37 $(0.09) (6.6)%Average Shallow Oil and Gas ad valorem, Severance, and other taxes (per Mcfe)$0.36 $0.35 $0.01 2.9 %Average Shallow Oil and Gas gathering costs (per Mcfe)$1.21 $0.92 $0.29 31.5 %Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)$0.35 $0.45 $(0.10) (22.2)%Average Shallow Oil and Gas depreciation, depletion and amortization costs (perMcfe)$2.14 $2.02 $0.12 5.9 % Total Average Shallow Oil and Gas costs (per Mcfe)$5.34 $5.11 $0.23 4.5 % Average Margin for Shallow Oil and Gas (per Mcfe)$(0.64) $(0.47) $(0.17) 36.2 %*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil andnatural gas,which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.Shallow Oil and Gas sales revenues were $131 million for the year ended December 31, 2013 compared to $135 million for the year ended December 31,2012. The $4 million decrease was primarily due to the 4.5% decrease in total volumes sold, offset, in part, by a 1.3% increase in the total average sales price.The increase in shallow oil and gas total average sales price is primarily the result of a $0.54 per Mcf increase in average market prices offset, in part, by a$0.44 per Mcf decrease due to various gas swap transactions that matured in each period. These gas swap transactions qualify as financial cash flow hedgesthat exist parallel to the underlying physical transactions. These financial hedges represented approximately 14.3 Bcf of our produced shallow oil and gas salesvolumes for the year ended December 31, 2013 at an average price of $5.20 per Mcf. For the year ended December 31, 2012, these financial hedges represented18.5 Bcf at an average price of $5.23 per Mcf. The hedging impact on the average sales price was a decrease of $0.44 per Mcf.Total costs for the shallow oil and gas segment were $149 million for the year ended December 31, 2013 compared to $148 million for the year endedDecember 31, 2012. The increase in total dollars and unit costs for the shallow oil and gas segment are due to the following items:•Shallow Oil and Gas lifting costs were $35 million for the year ended December 31, 2013 compared to $40 million for the year ended December 31,2012. The $5 million decrease in total costs and $0.09 per Mcfe decrease in average unit costs is due to lower well tending costs, and lower salt water disposalcosts offset, in part, by an increase in accretion expense on the well plugging liability. The related decrease in unit costs is offset, in part, by the decrease insales volumes.•Shallow Oil and Gas ad valorem, severance and other taxes remained consistent at $10 million for the year ended December 31, 2013 and 2012. Theincrease of $0.01 per Mcfe in unit costs was due to the decrease in sales volumes.•Shallow Oil and Gas gathering costs were $34 million for the year ended December 31, 2013 compared to $26 million for the year endedDecember 31, 2012. Gathering costs increased $8 million primarily due to increased firm transportation costs in the period-to-period comparison. Unit costswere further impacted by lower sales volumes.58•Shallow Oil and Gas direct administrative, selling and other costs were $10 million for the year ended December 31, 2013 compared to $13 millionfor the year ended December 31, 2012. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gassegments based on a combination of production and employee counts. The $3 million decrease in the period-to-period comparison is due to reduced directadministrative labor and Shallow Oil and Gas volumes representing a smaller proportion of CONSOL Energy's total gas sales volumes. These decreases incosts were offset, in part, by lower sales volumes.•Depreciation, depletion and amortization attributable to the Shallow Oil & Gas segment was $60 million for the year ended December 31, 2013compared to $59 million for the year ended December 31, 2012 There was approximately $52 million, or $1.87 per unit-of production, of depreciation,depletion and amortization related to Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation forthe year ended December 31, 2013. There was approximately $51 million, or $1.75 per unit-of-production, of depreciation, depletion and amortization relatedto Shallow Oil and Gas gas and related well equipment that was reflected on a units-of-production method of depreciation for the year ended December 31,2012. There was approximately $8 million, or $0.27 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that isreflected on a straight-line basis for the year ended December 31, 2013. There was $8 million, or $0.27 per Mcf, of depreciation, depletion and amortizationrelated to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2012.OTHER GAS SEGMENTThe other gas segment includes activity not assigned to the Marcellus, CBM, or shallow oil & 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 and the Utica Shale in Ohio. Revenue from theseoperations were approximately $19 million for the year ended December 31, 2013 and $10 million for the year ended December 31, 2012. Total costs related tothese other sales were $27 million for the year ended December 31, 2013 and $21 million for the year ended December 31, 2012. A per unit analysis of theother operating costs in Chattanooga Shale and Utica Shale is not meaningful due to the relatively low volumes sold 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 segment. Royalty interest gas sales revenue was $63 million for the year ended December 31, 2013 compared to $50 million for the year endedDecember 31, 2012. 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 increase. For the Years Ended December 31, 2013 2012 Variance PercentChangeGas Royalty Interest Sales Volumes (Bcf)15.3 18.0 (2.7) (15.0)%Average Sales Price (per Mcf)$4.13 $2.74 $1.39 50.7 %Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas salesrevenues were $7 million for the year ended December 31, 2013 compared to $3 million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangePurchased Gas Sales Volumes (Bcf)1.6 1.1 0.5 45.5%Average Sales Price (per Mcf)$4.12 $3.03 $1.09 36.0%Other income was $58 million for the year ended December 31, 2013 compared to $57 million for the year ended December 31, 2012. The $1 millionchange was due to various transactions that occurred throughout both periods, none of which were individually material.59General and Administrative costs are allocated to the total gas segment based on percentage of total revenue and percentage of total projected capitalexpenditures. Costs were $45 million for the year ended December 31, 2013 and $40 million for the year ended December 31, 2012. Refer to the discussion oftotal company general and administrative costs contained in the section "Net Income Attributable to CONSOL Energy Shareholders" of this quarterly reportfor a detailed cost explanation.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 $53 million for the year ended December 31, 2013 compared to $39 million for the year ended December 31,2012. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed tothe period-to-period change. For the Years Ended December 31, 2013 2012 Variance PercentChangeGas Royalty Interest Sales Volumes (Bcf)15.3 18.0 (2.7) (15.0)%Average Cost (per Mcf)$3.47 $2.16 $1.31 60.6 %Purchased gas volumes represent volumes of gas purchased from third-party producers that are subsequently sold to customers. Changes in the averagecost per Mcf were due to overall price changes and contractual differences among customers in the period-to-period comparison. Purchased gas costs were $5million for the year ended December 31, 2013 compared to $3 million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangePurchased Gas Sales Volumes (Bcf)1.6 1.1 0.5 45.5%Average Cost (per Mcf)$3.05 $2.44 $0.61 25.0%Exploration and other costs were $61 million for the year ended December 31, 2013 compared to $39 million for the year ended December 31, 2012.The $22 million increase in costs is primarily related to the following items: For the Years Ended December 31, 2013 2012 Variance PercentChangeMarcellus Title Defects$23 $4 $19 475.0 %Dry Hole Costs8 3 5 166.7 %Exploration Costs20 18 2 11.1 %Lease Expiration Costs10 14 (4) (28.6)%Total Exploration and Other Costs$61 $39 $22 56.4 %•CONSOL Energy has completed its review of the title defect notice, asserted by Noble, and working in collaboration with Noble, conceded titledefects on acreage which had a carrying value to CONSOL Energy of $23 million for the year ended December 31, 2013 compared to $4 million forthe year ended December 31, 2012.•Dry hole costs increased $5 million due to various transactions that occurred throughout both periods, none of which were individually material.•Exploration expense increased $2 million due to increased exploratory expenses associated primarily with the Utica operating areas and varioustransactions that occurred throughout both periods, none of which were individually material.•Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics.The $4 million decrease is due to fewer lease expirations in the current period when compared with the prior period.Other corporate expenses were $92 million for the year ended December 31, 2013 compared to $77 million for the year ended December 31, 2012. The$15 million increase in the period-to-period comparison was made up of the following items:60 For the Years Ended December 31, 2013 2012 Variance PercentChangeUnutilized firm transportation$35 $16 $19 118.8 %Stock-based compensation24 18 6 33.3 %Bank fees7 7 — — %Short-term incentive compensation20 26 (6) (23.1)%PA Impact fees— 4 (4) (100.0)%Other6 6 — — %Total Other Corporate Expenses$92 $77 $15 19.5 %•Unutilized firm transportation costs represent pipeline transportation capacity the gas segment has obtained to enable gas production to flowuninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The $19 million increase is due toincreased firm transportation capacity which has not been utilized by active operations.•Stock-based compensation was $6 million higher in the period-to-period comparison primarily due to additional non-cash expense and acceleratednon-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to theprior year. The new program replaces several previously provided long-term executive compensation award programs. The compensation expense ofthe CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.•Bank Fees remained consistent in the period-to-period comparison.•The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predeterminedtargets for safety, production and unit costs. Short-term incentive compensation expense decreased $6 million due to lower projected payouts in the2013 period.•PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the firstquarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. Aspart of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate towells drilled in the applicable period, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.•Other corporate related expense remained consistent in the period-to-period comparison.Interest expense related to the gas segment was $9 million for the year ended December 31, 2013 compared to $5 million for the year ended December 31,2012. Interest was incurred by the gas segment on the CNX Gas revolving credit facility and a capital lease. The $4 million increase was primarily due tohigher levels of borrowings on the revolving credit facility throughout the period-to-period comparison.61TOTAL COAL SEGMENT ANALYSIS - CONTINUING OPERATIONS for the year ended December 31, 2013 compared to the year endedDecember 31, 2012:The coal segment contributed $337 million of earnings before income tax from continuing operations in the year ended December 31, 2013 compared to$592 million in the year ended December 31, 2012. For the Year Ended Increase (Decrease) from Year Ended December 31, 2013 December 31, 2012 ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoal ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoalSales: Produced Coal$1,388 $160 $447 $— $1,995 $(43) $(50) $(59) $(5) $(157)Purchased Coal— — — 23 23 — — — 6 6Total Outside Sales1,388 160 447 23 2,018 (43) (50) (59) 1 (151)Freight Revenue— — — 35 35 — — — (72) (72)Other Income2 2 — 98 102 — (4) — (226) (230)Total Revenue and OtherIncome1,390 162 447 156 2,155 (43) (54) (59) (297) (453)Costs and Expenses: Beginning inventorycosts33 — 21 — 54 (34) (2) 5 — (31)Total direct costs626 79 196 101 1,002 33 (16) 12 (44) (15)Total royalty/productiontaxes68 5 26 2 101 (6) (4) (4) (1) (15)Total direct services tooperations134 15 27 163 339 (20) (6) 5 (54) (75)Total retirement anddisability58 7 25 10 100 (3) (3) (3) (10) (19)Depreciation, depletionand amortization116 15 41 46 218 (4) (7) 4 13 6Ending inventory costs(21) — (10) — (31) 12 — 11 — 23Total Costs and Expenses1,014 121 326 322 1,783 (22) (38) 30 (96) (126)Freight Expense— — — 35 35 — — — (72) (72)Total Costs of Goods Sold1,014 121 326 357 1,818 (22) (38) 30 (168) (198)Earnings (Loss) BeforeIncome Taxes$376 $41 $121 $(201) $337 $(21) $(16) $(89) $(129) $(255)62THERMAL COAL SEGMENTThe thermal coal segment contributed $376 million to total Company earnings before income tax for the year ended December 31, 2013 compared to$397 million for the year ended December 31, 2012. The thermal coal revenue and cost components on a per unit basis for these periods are as follows: For the Years Ended December 31, 2013 2012 Variance PercentChangeCompany Produced Thermal Tons Sold (in millions)21.5 20.7 0.8 3.9%Average Sales Price Per Thermal Ton Sold$64.78 $69.08 $(4.30) (6.2%) Beginning Inventory Costs Per Thermal Ton$50.86 $61.92 $(11.06) (17.9%) Total Direct Operating Costs Per Thermal Ton Produced$29.55 $29.29 $0.26 0.9%Total Royalty/Production Taxes Per Thermal Ton Produced3.22 3.65 (0.43) (11.8%)Total Direct Services to Operations Per Thermal Ton Produced6.31 7.61 (1.30) (17.1%)Total Retirement and Disability Per Thermal Ton Produced2.76 3.01 (0.25) (8.3%)Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced5.45 5.93 (0.48) (8.1%) Total Production Costs Per Thermal Ton Produced$47.29 $49.49 $(2.20) (4.4%) Ending Inventory Costs Per Thermal Ton$(50.82) $(50.89) $0.07 0.1% Total Costs of Goods Sold Per Thermal Ton Sold$47.33 $50.00 $(2.67) (5.3%) Average Margin Per Thermal Ton Sold$17.45 $19.08 $(1.63) (8.5%)Thermal coal revenue was $1,388 million for the year ended December 31, 2013 compared to $1,431 million for the year ended December 31, 2012. The$43 million decrease was attributable to a $4.30 per ton lower average sales price offset, in part, by a 0.8 million increase in tons sold. The lower averagethermal coal sales price in the 2013 period was the result of the renewal of several domestic thermal contracts whose pricing was reduced effective January 1,2013. The decrease in price was partially offset by 2.0 million tons of thermal coal being priced on the export market at an average sales price of $63.04 per tonfor the year ended December 31, 2013 compared to 2.1 million tons at an average price of $61.28 per ton for the year ended December 31, 2012.Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity inearnings of affiliates is insignificant to the total segment activity.Total cost of goods sold is comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in the period.Total cost of goods sold for thermal coal was $1,014 million for the year ended December 31, 2013, or $22 million lower than the $1,036 million for the yearended December 31, 2012. Total cost of goods sold for thermal coal was $47.33 per ton in the year ended December 31, 2013 compared to $50.00 per ton in theyear ended December 31, 2012. The decrease in total dollars and unit costs per thermal ton was due to the items described below.Direct operating costs are comprised of labor, supplies, maintenance, power and preparation plant charges related to the extraction and sale of coal.These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Direct operating costs related to thethermal coal segment were $626 million in the year ended December 31, 2013 compared to $593 million in the year ended December 31, 2012. Directoperating costs were $29.55 per ton produced in the current period compared to $29.29 per ton produced in the prior period. Changes in the average directoperating costs per thermal ton produced were primarily related to the following items:•In 2013, CONSOL Energy entered into a new longwall lease at Bailey Mine which resulted in higher cost per ton produced in the period-to-periodcomparison.•Project expense increased in the 2013 period due to a longwall overhaul and a waterline extension project at Bailey Mine.•Power expense increased in the 2013 period due to an increase in rates in the current year.63•Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.•On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal fromboth the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled for approximatelythree weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period,which resulted in lower direct operating costs per ton produced.•The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-periodcomparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall averagedirect operating costs per ton produced.Royalties and production taxes were $68 million for the year ended December 31, 2013 compared to $74 million for the year ended December 31, 2012.The $6 million decrease in total dollars was primarily due to the the lower average sales prices which is the basis for most production taxes. The unit costs perthermal ton produced decreased $0.43 per ton to $3.22 per ton produced, due to the increase in production volumes.Direct services to the operations are comprised of items which support groups manage on behalf of the coal operations. Costs included in direct servicesare comprised of subsidence costs, direct administrative and selling costs, permitting and compliance costs, mine closing and reclamation costs, and watertreatment costs. The cost of these support services was $134 million in the current period compared to $154 million in the prior period. Direct services to theoperations were $6.31 per ton produced in the current period compared to $7.61 per ton produced in the prior period. Changes in the average direct service tooperations cost per thermal ton produced were primarily related to the following items:•Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing andnature of properties undermined in the period-to-period comparison.•Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 VoluntarySeverance Incentive Plan, as discussed previously.•Unit costs decreased due to the increase in production volumes since fixed costs are spread over more tons.Retirement and disability costs are comprised of the expenses related to the Company's long-term liabilities, such as other post-employment benefits(OPEB), the salary retirement plan, workers' compensation, coal workers' pneumoconiosis (CWP) and long-term disability. These liabilities are actuariallycalculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Theretirement and disability costs attributable to the thermal coal segment were $58 million for the year ended December 31, 2013 compared to $61 million for theyear ended December 31, 2012. The decrease in total dollars was primarily attributable to an increase in discount rates used to calculate the 2013 cost of thelong-term liabilities and a modification of the salaried other post-employment benefit plan that occurred after December 31, 2012. Average cost per thermal tonproduced decreased $0.25 per ton to $2.76 per ton produced due to the increase in production volumes.Depreciation, depletion and amortization for the thermal coal segment was $116 million for the year ended December 31, 2013 compared to $120 millionfor the year ended December 31, 2012. Unit costs per thermal ton produced decreased $0.48 in the period-to-period comparison to $5.45 per ton. Total dollarsand unit costs decreased primarily due the idling of the Fola Complex in August 2012. The decrease was off-set, in part, by lower amortization and depletionfor the 2012 period due to the structural failure that affected production at both the Bailey and Enlow Fork Mines. Also, unit costs improved due to theincrease in production volumes.Changes in thermal coal inventory volumes and carrying value resulted in $12 million of cost of goods sold in the year ended December 31, 2013compared to $34 million of cost of goods sold in the year ended December 31, 2012. Thermal coal inventory was 0.4 million tons at December 31, 2013compared to 0.6 million tons at December 31, 2012.64HIGH VOL METALLURGICAL COAL SEGMENTThe high volatile metallurgical coal segment contributed $41 million to total Company earnings before income tax for the year ended December 31, 2013compared to $57 million for the year ended December 31, 2012. The high volatile metallurgical coal revenue and cost components on a per unit basis for theseperiods are as follows: For the Years Ended December 31, 2013 2012 Increase(Decrease) PercentChangeCompany Produced High Vol Met Tons Sold (in millions)2.5 3.3 (0.8) (24.2%)Average Sales Price Per High Vol Met Ton Sold$63.44 $63.93 $(0.49) (0.8%) Beginning Inventory Costs Per High Vol Met Ton$— $— $— —% Total Direct Operating Costs Per High Vol Met Ton Produced$31.39 $28.98 $2.41 8.3%Total Royalty/Production Taxes Per High Vol Met Ton Produced1.82 2.72 (0.90) (33.1%)Total Direct Services to Operations Per High Vol Met Ton Produced5.96 6.22 (0.26) (4.2%)Total Retirement and Disability Per High Vol Met Ton Produced2.94 3.10 (0.16) (5.2%)Total Depreciation, Depletion and Amortization Costs Per High Vol MetTon Produced5.96 6.63 (0.67) (10.1%) Total Production Costs Per High Vol Met Ton Produced$48.07 $47.65 $0.42 0.9% Ending Inventory Costs Per High Vol Met Ton$— $— $— —% Total Costs Per High Vol Met Ton Sold$48.07 $48.43 $(0.36) (0.7%) Margin Per High Vol Met Ton Sold$15.37 $15.50 $(0.13) (0.8%)High volatile metallurgical coal revenue was $160 million for the year ended December 31, 2013 compared to $210 million for the year endedDecember 31, 2012. Average sales prices for high volatile metallurgical coal decreased $0.49 per ton in a period-to-period comparison. CONSOL Energy priced2.3 million tons of high volatile metallurgical coal in the export market at an average sales price of $61.62 per ton for the year ended December 31, 2013compared to 2.8 million tons at an average price of $60.75 per ton for the year ended December 31, 2012. The remaining tons sold in the period-to-periodcomparison were sold on the domestic market.Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate high volatilemetallurgical coal mines. The equity in earnings of affiliates is insignificant to the total segment activity.Total cost of goods sold is comprised of changes in high volatile metallurgical coal inventory, both volumes and carrying values, and costs of tonsproduced in the period. Total cost of goods sold for high volatile metallurgical coal was $121 million for the year ended December 31, 2013, or $38 millionlower than the $159 million for the year ended December 31, 2012. Total cost of goods sold for high volatile metallurgical coal was $48.07 per ton in the yearended December 31, 2013 compared to $48.43 per ton in the year ended December 31, 2012. The decrease in total dollars and unit costs per high volatilemetallurgical ton was due to the items described below.Direct operating costs related to the high volatile metallurgical coal segment were $79 million in the year ended December 31, 2013 compared to $95million in the year ended December 31, 2012. The reduction in total dollars was primarily due to a reduction in mine maintenance and supply expense as aresult of the shutdown of the Fola Mining Complex in August 2012, along with the mix of mines which sold on the high volatile coal market in the period-to-period comparison. Direct operating costs were $31.39 per ton produced in the current period compared to $28.98 per ton produced in the prior period. Theincrease in the average direct operating costs per high volatile metallurgical ton produced was primarily due to 0.8 million fewer tons produced. This resulted infixed costs being allocated over less tons, resulting in higher unit costs.Royalties and production taxes were $5 million or improved $4 million in the current period primarily due to the shutdown of the Fola Mining Complexin August 2012 and the mix of mines which sold on the high volatile metallurgical coal market. Mines with higher royalty rates produced a larger portion of thehigh volatile metallurgical coal shipped in the prior65period compared to the current period. Unit costs decreased due to lower total dollars spent, and were offset, in part, by the lower volumes produced.Direct service costs for high volatile metallurgical coal were $15 million in the current period compared to $21 million in the prior period. Direct servicesto the operations for high volatile metallurgical coal were $5.96 per ton in the current period compared to $6.22 per ton in the prior period. Changes in theaverage direct services to operations cost per ton for high volatile metallurgical coal produced were primarily related to the following items:•Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing andnature of properties undermined in the period-to-period comparison. The decrease in unit costs was offset, in part, by the reduction in productiontons.•Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 VoluntarySeverance Incentive Plan, as discussed previously. The decrease in unit costs was also offset, in part, by the reduction in production tons.Retirement and disability costs attributable to the high volatile metallurgical coal segment were $7 million for the year ended December 31, 2013compared to $10 million for the year ended December 31, 2012. The decrease in total high volatile metallurgical coal retirement and disability total dollars andunit costs was primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salariedother post-employment benefit plan that occurred after December 31, 2012. The decrease in unit costs was off-set, in part, by the lower volumes produced.Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $15 million for the year ended December 31, 2013 and $22million for the year ended December 31, 2012. Total dollars and unit costs per high volatile metallurgical ton produced were lower in the year endedDecember 31, 2013 compared to the year ended December 31, 2012 due to the 0.8 million decrease in production tons which resulted in lower depletionexpense.There were no changes in volumes or carrying value of coal inventory in the year ended December 31, 2013 and December 31, 2012. There was no highvolatile metallurgical coal inventory at December 31, 2013 or December 31, 2012.66LOW VOL METALLURGICAL COAL SEGMENTThe low volatile metallurgical coal segment contributed $121 million to total Company earnings before income tax in the year ended December 31, 2013compared to $210 million in the year ended December 31, 2012. 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, 2013 2012 Variance PercentChangeCompany Produced Low Vol Met Tons Sold (in millions)4.8 3.6 1.2 33.3%Average Sales Price Per Low Vol Met Ton Sold$92.64 $140.11 $(47.47) (33.9%) Beginning Inventory Costs Per Low Vol Met Ton$86.38 $67.60 $18.78 27.8% Total Direct Operating Costs Per Low Vol Met Ton Produced$41.34 $50.88 $(9.54) (18.8%)Total Royalty/Production Taxes Per Low Vol Met Ton Produced5.54 8.33 (2.79) (33.5%)Total Direct Services to Operations Per Low Vol Met Ton Produced5.66 6.03 (0.37) (6.1%)Total Retirement and Disability Per Low Vol Met Ton Produced5.28 7.63 (2.35) (30.8%)Total Depreciation, Depletion and Amortization Costs Per Low Vol MetTon Produced8.69 10.23 (1.54) (15.1%) Total Production Costs Per Low Vol Met Ton Produced$66.51 $83.10 $(16.59) (20.0%) Ending Inventory Costs Per Low Vol Met Ton$(65.68) $(86.38) $20.70 24.0% Total Costs Per Low Vol Met Ton Sold$67.53 $81.89 $(14.36) (17.5%) Margin Per Low Vol Met Ton Sold$25.11 $58.22 $(33.11) (56.9%)Low volatile metallurgical coal revenue was $447 million for the year ended December 31, 2013 compared to $506 million for the year endedDecember 31, 2012. The $59 million decrease was primarily attributable to a $47.47 per ton lower average sales price. The average sales price for low volatilemetallurgical coal decreased in the period-to-period comparison due to the weakening in the global metallurgical coal market. For the 2013 period, 3.7 milliontons of low volatile metallurgical coal were priced on the export market at an average price of $83.81 per ton compared to 2.6 million tons at an average price of$125.37 per ton for the 2012 period. The remaining tons sold in the period-to-period comparison were sold on the domestic market.Total cost of goods sold is comprised of changes in low volatile metallurgical coal inventory, both volumes and carrying values, and costs of tonsproduced in the period. Total cost of goods sold for low volatile metallurgical coal was $326 million for the year ended December 31, 2013, or $30 millionhigher than the $296 million for the year ended December 31, 2012. Total cost of goods sold for low volatile metallurgical coal was $67.53 per ton in the yearended December 31, 2013 compared to $81.89 per ton in the year ended December 31, 2012. The increase in total dollars and decrease in unit costs per lowvolatile metallurgical ton was due to the items described below.Direct operating costs related to the low volatile metallurgical coal segment were $196 million in the year ended December 31, 2013 compared to $184million in the year ended December 31, 2012. Direct operating costs increased due to the Buchanan Mine longwall being temporarily idled in March, April,and October of 2012. The increase in costs was partially offset by several cost saving initiatives at the Buchanan Mine in the 2013 period, such as, slowingthe pace of major maintenance projects, right sizing the workforce to fit the five-day work schedule implemented earlier in 2013, and opening the HornMountain portal, which allowed employees to enter the mine much closer to the longwall face. Direct operating costs were $41.34 per ton produced in thecurrent period compared to $50.88 per ton produced in the prior period. Low volatile metallurgical coal production was 1.2 million tons higher in the currentperiod primarily due to Buchanan Mine being temporarily idled in the 2012 period, as mentioned above. This resulted in 2012 fixed costs being allocated overless tons, resulting in higher unit costs in the prior period.Royalties and production taxes were $26 million for the year ended December 31, 2013 compared to $30 million for the year ended December 31, 2012.Unit costs improved $2.79 per low volatile metallurgical ton produced to $5.54 per ton67produced in the current period compared to $8.33 per ton produced in the prior period. The decrease in total dollars and unit costs was primarily related to the$47.47 per ton decrease in average sales price, which is the basis for most royalties and production taxes.Direct services costs for low volatile metallurgical coal were $27 million in the current period and $22 million in the prior period. The increase in totaldollars was primarily due to higher water treatment and subsidence costs in the 2013 period. The increase in costs is a direct result of the Buchanan Minebeing temporarily idled in the 2012 period. Average cost per low volatile metallurgical ton produced decreased $0.37 per ton due to the increase in productiontons.Retirement and disability costs attributable to the low volatile metallurgical coal segment were $25 million for the year ended December 31, 2013compared to $28 million for the year ended December 31, 2012. The decrease in the low volatile metallurgical coal retirement and disability costs total dollarswas primarily attributable to an increase in discount rates used to calculate the 2013 cost of the long-term liabilities and a modification of the salaried otherpost-employment benefit plan that occurred after December 31, 2012. This, coupled with the increase in volumes, resulted in an improvement in the unit costsof $2.35 per ton in the period-to-period comparison.Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $41 million for the year ended December 31, 2013 and $37million for the year ended December 31, 2012. Unit costs per low volatile metallurgical ton produced were $1.54 per ton lower in the current period due to the1.2 million increase in production tons.Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in an increase of $11 million to cost of goods sold in the yearended December 31, 2013 and a decrease of $5 million to cost of goods sold in the year ended December 31, 2012. Produced low volatile metallurgical coalinventory was 0.2 million tons at December 31, 2013 compared to 0.3 million tons at December 31, 2012.OTHER COAL SEGMENTThe other coal segment had a loss before income tax of $201 million for the year ended December 31, 2013 compared to a loss before income tax of $72million for the year ended December 31, 2012. 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 0.1 million tons of coal which was recovered during the reclamation process atidled facilities for the year ended December 31, 2012. No coal was recovered during the reclamation process at idled facilities for the year ended December 31,2013. The primary focus of the activity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mininghas occurred. The tons sold are incidental to total 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 and coal purchased from third parties and sold directly to our customers. The revenues were $23 million for the year ended December 31, 2013compared to $17 million for the year ended December 31, 2012.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 by freight expense. Freight revenue was $35 million for the year ended December 31, 2013 compared to $107 million for theyear ended December 31, 2012. The $72 million decrease in freight revenue was due to decreased shipments under contracts which CONSOL Energycontractually provides transportation services.Miscellaneous other income was $98 million for the year ended December 31, 2013 compared to $324 million for the year ended December 31, 2012.The $226 million decrease is due to the following items:•Gain on sale of assets attributable to the Other Coal segment was $46 million in the year ended December 31, 2013 compared to $271 million in theyear ended December 31, 2012. The decrease of $225 million was primarily related to 2012 sales of non-producing assets in the Northern PowderRiver Basin that resulted in a gain on sale of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in a gain onsale of $112 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in a gain on sale of $25 million and the sale of 50%interest in a joint venture in Alberta, Canada that resulted in a gain on sale of $15 million. See Note 3—Acquisitions and Dispositions in the Notesto the Audited Consolidated Financial Statements in Item 8 of this Form6810-K for additional detail of these sales. The remaining $2 million decrease was related to various transactions that occurred throughout bothperiods, none of which were individually material.•In the year ended December 31, 2013, $5 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyoraccident. There is no assurance that additional proceeds from the incident will be received.•The remaining $6 million decrease in other income is due to various items, none of which were individually material.Other coal segment total costs were $357 million for the year ended December 31, 2013 compared to $525 million for the year ended December 31,2012. The decrease of $168 million was due to the following items: For the Years Ended December 31, 2013 2012 VarianceFreight Expense $35 $107 $(72)Bailey Belt Incident — 42 (42)Closed and Idle Mines 107 134 (27)Litigation Contingencies — 17 (17)Voluntary Incentive Separation Program — 13 (13)General and Administrative Expense 100 102 (2)Purchased Coal 43 41 2Stock-based Compensation 33 23 10Other 39 46 (7) Total other coal segment costs $357 $525 $(168)•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 offset by freight revenue. The $72 million decrease in freight expense was due to decreasedshipments under contracts which CONSOL Energy contractually provides transportation services.•Bailey Belt Incident costs represent expenses during the belt-reconstruction period. The mine was idled during this period but there was continuedadvancement of the mine and on-going projects which resulted in $42 million of expense.•Closed and idle mine costs decreased approximately $27 million for the year ended December 31, 2013 compared to the year ended December 31,2012. Closed and idle mine costs decreased $16 million due to the decision to shutdown the Fola Mining Complex in August 2012 and $18 milliondue to the decision to idle operations at Buchanan Mine for three months in 2012. These decrease were offset, in part, by an increase of $8 million incosts incurred primarily by the Amonate Complex. Other changes in the operational status of various other mines, between idled and operatingthroughout both periods, none of which were individually material resulted in an additional $1 million decrease.•Litigation Contingencies decreased $17 million in the year-to-year comparison due to various items. See Note 24- Commitments and ContingentLiabilities in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Companyexpense.•In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation supportemployees with 30 years of service, or more. Under this program, eligible employees who accepted the offer received a severance payment equal to oneyear's salary. Approximately 100 employees volunteered for the program. Severance pay was approximately $13 million.•General and Administrative Expense decreased $2 million due to various items that occurred in both periods, none of which were individuallymaterial.•Purchased coal costs increased $2 million due to higher amounts of coal that was purchased to fulfill various contracts.•Stock-based compensation was $10 million higher in the period-to-period comparison primarily due to additional non-cash expense and acceleratednon-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program. The new programreplaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not bematerially different from the total expense of the previous programs over the three-year performance period.•Other expenses related to the coal segment decreased $7 million due to various transactions that occurred throughout both periods, none of whichwere individually material.69OTHER SEGMENT ANALYSIS for the year ended December 31, 2013 compared to the year ended December 31, 2012:The other segment includes activity from the sales of industrial supplies, coal terminal operations and various other corporate activities that are notallocated to the gas or coal segment. The other segment had a loss before income tax of $288 million for the year ended December 31, 2013 compared to a lossbefore income tax of $224 million for the year ended December 31, 2012. The other segment also includes the total company income tax benefit of $33 millionfor the year ended December 31, 2013 compared to the total company income tax expense of $89 million for the year ended December 31, 2012. For the Years Ended December 31, 2013 2012 Variance PercentChangeSales—Outside$260 $294 $(34) (11.6)%Other Income19 6 13 216.7 %Total Revenue279 300 (21) (7.0)%Cost of Goods Sold and Other Charges332 292 40 13.7 %Depreciation, Depletion & Amortization13 12 1 8.3 %Taxes Other Than Income Tax11 5 6 120.0 %Interest Expense211 215 (4) (1.9)%Total Costs567 524 43 8.2 %Loss Before Income Tax(288) (224) (64) (28.6)%Income Tax (Benefit) Expense(33) 89 (122) (137.1)%Net Loss$(255) $(313) $58 18.5 %Industrial supplies:Total revenue from industrial supplies was $218 million for the year ended December 31, 2013 compared to $244 million for the year endedDecember 31, 2012. The decrease was related to lower sales volumes.Total costs related to industrial supply sales were $216 million for the year ended December 31, 2013 compared to $239 million for the year endedDecember 31, 2012. The decrease of $23 million was primarily related to lower sales volumes and various changes in inventory costs, none of which wereindividually material.Transportation operations:Total revenue from transportation operations was $47 million for the year ended December 31, 2013 compared to $52 million for the year endedDecember 31, 2012. The decrease of $5 million was primarily due to decreased thru-put volumes as well as lower per ton thru-put rates for the current period.Total costs related to the transportation operations was $41 million for the year ended December 31, 2013 compared to$43 million for the year endedDecember 31, 2012. The $2 million decrease was due to lower thru-put volumes.Miscellaneous other:Additional other income of $14 million was recognized for the year ended December 31, 2013 compared to $4 million for the year ended December 31,2012. The $10 million increase was primarily due to the following items: For the Years Ended December 31, 2013 2012 VariancePennsylvania Turnpike Settlement $9 $— $9Equity in Earnings of Affiliates 1 — 1Towing Income 1 1 —Other 3 3 — $14 $4 $1070•Pennsylvania Turnpike Settlement relates to mediation with the PA Turnpike Commission that was settled for $9 million.•Equity in Earnings increased $1 million due to an increase in earnings from our Equity Affiliates in the current period.•Towing income remained consistent in the period to period comparison.•Other income remained consistent in the period to period comparison.Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges.Total other costs were $310 million for the year ended December 31, 2013 compared to $242 million for the year ended December 31, 2012. Other corporatecosts increased due to the following items: For the Years Ended December 31, 2013 2012 VariancePension Settlement $39 $— $39CNX Gas Shareholder Settlement 19 — 19Corporate Initiative Fees and Other Legal Charges 15 4 11Accelerated Bank Fees 3 — 3Bank Fees 15 13 2Interest Expense 211 215 (4)Other 8 10 (2) $310 $242 $68•Pension settlement expenses were required when lump sum distributions made for the 2013 plan year exceeded the total of the service and interestcosts for the 2013 plan year.•The CNX Gas shareholder settlement is the result of an agreement in principle for resolution of the class actions brought by shareholders of CNXGas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not alreadyown for $38.25 per share in May 2010. The total settlement provides for a payment to the plaintiffs of $43 million, of which the Company paid $19million.•Corporate initiative fees and other legal charges reflect various charges for services related to corporate initiatives to evaluate various asset sales. Thesefees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas Shareholder case. See Note 11 -Property, Plant and Equipment and Note 24 - Commitments and Contingent Liabilities of the Notes to the Audited Consolidated Financial Statementsin Item 8 of this Form 10-K for additional information.•Accelerated Bank Fees represents accelerated amortization of the previously deferred fees in relation to the capacity reduction in CONSOL Energy'srevolving credit facility from $1.5 billion to $1.0 billion.•Bank fees increased $2 million mainly due to higher borrowings on the CNX Gas revolving credit facilities in the period-to-period comparison.•Interest Expense decreased $4 million primarily due to a reduction in capitalized interest due to lower capital expenditures for major constructionprojects in the current period.•Other corporate items decreased $2 million due to various transactions that occurred throughout both periods, none of which were individuallymaterial.Income Taxes:The 2013 effective tax rate is the result of lower pre-tax income without a corresponding reduction in the percentage depletion deduction, resulting in a taxloss from continuing operations in the current period. CONSOL Energy's effective tax rate is significantly impacted by the relationship between the pre-taxearnings and percentage depletion. See Note 7-Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K foradditional information. For the Years Ended December 31, 2013 2012 Variance PercentChangeTotal Company Earnings Before Income Tax$46 $407 $(361) (88.8)%Income Tax (Benefit) Expense$(33) $89 $(122) (137.5)%Effective Income Tax Rate(72.0)% 22.0% (94.0)% 71Results of OperationsYear Ended December 31, 2012 Compared with the Year Ended December 31, 2011Net Income Attributable to CONSOL Energy ShareholdersCONSOL Energy reported net income attributable to CONSOL Energy shareholders of $388 million, or $1.70 per diluted share, for the year endedDecember 31, 2012. Net income attributable to CONSOL Energy shareholders was $632 million, or $2.76 per diluted share, for the year ended December 31,2011. Included in net income is income from continuing operations of $318 million, or $1.39 per diluted share, for the year ended December 31, 2012. Incomefrom continuing operations was $682 million, or $2.98 per diluted share, for the year ended December 31, 2011. Also included in net income is income fromdiscontinued operations of $70 million, or $0.31 per diluted share, for the year ended December 31, 2012. There was a loss from discontinued operations of$49 million, or a loss of $0.22 per diluted share, for the year ended December 31, 2011.The total gas division includes Marcellus, coalbed methane (CBM), shallow oil and gas, and other gas. The total gas division contributed $39 millionof earnings before income tax for the year ended December 31, 2012 compared to $130 million for the year ended December 31, 2011. Total gas productionwas 156.3 billion net cubic feet for the year ended December 31, 2012 compared to 153.5 billion net cubic feet for the year ended December 31, 2011. Totalgas production increased primarily due to the on-going drilling program, partially offset by 10.7 billion net cubic feet of production related to both the 2011divestiture of Antero Resources Appalachian Corp. (Antero) and the 2011 Noble Joint Venture. Production also decreased due to the Buchanan Mine idling forportions of 2012 as previously discussed.The following table presents a breakout of net liquid and natural gas sales information to assist in the understanding of the Company’s production andsales portfolio. For the Years Ended December 31, in thousands (unless noted) 2012 2011 Variance PercentChangeLIQUIDS NGLs: Sales Volume (MMcfe) 610 — 610 100.0 %Sales Volume (Mbbls) 102 — 102 100.0 %Gross Price ($/Bbl) $52.32 $— $52.32 100.0 %Gross Revenue $5,314 $— $5,314 100.0 % Oil: Sales Volume (MMcfe) 600 563 37 6.6 %Sales Volume (Mbbls) 100 94 6 6.4 %Gross Price ($/Bbl) $92.58 $94.20 $(1.62) (1.7)%Gross Revenue $9,252 $8,729 $523 6.0 % GAS Sales Volume (MMcf) 155,052 152,940 2,112 1.4 %Sales Price ($/Mcf) $2.94 $4.25 $(1.31) (30.8)%Hedging Impact ($/Mcf) $1.22 $0.63 $0.59 93.7 %Gross Revenue $645,053 $743,038 $(97,985) (13.2)% The average sales price and average costs for all active gas operations were as follows: For the Years Ended December 31, 2012 2011 Variance PercentChangeAverage Sales Price (per Mcfe)$4.22 $4.90 $(0.68) (13.9)%Average Costs (per Mcfe)3.37 3.53 (0.16) (4.5)%Margin$0.85 $1.37 $(0.52) (38.0)%72Total gas division outside sales revenues were $659 million for the year ended December 31, 2012 compared to $752 million for the year endedDecember 31, 2011. The decrease was primarily due to the 13.9% reduction in average price per Mcfe, offset, in part, by the 2% increase in volumes sold.The decrease in average sales price is the result of the decline in general market prices, partially offset by various gas swap transactions that occurredthroughout both periods. The gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. Thesefinancial hedges represented approximately 76.9 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2012 at an average priceof $5.25 per per Mcf. These financial hedges represented 84.0 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2011 atan average price of $5.21 per Mcf.Changes in the average cost per Mcfe of gas sold were primarily related to the following items:•Higher volumes in the period-to-period comparison due to the on-going drilling program, offset, in part, by 10.7 billion cubic feet divested in the2011 Noble and the 2011 Antero transactions resulted in lower average costs per Mcfe sold. Fixed costs are allocated over increased volumes,resulting in lower unit costs.•Lower units-of-production depreciation, depletion and amortization rates for producing properties. These rates were generally calculated using the netbook value of assets divided by either proved or proved developed reserve additions. Increased proved and proved developed reserves relative to thenet book value of the producing assets as compared with the prior year resulted in a lower units-of-production rate.•Lower direct administrative, selling and other costs per Mcfe sold due to increased sales volumes and decreased actual dollars as a result of lowerdirect administrative labor and other costs.•Gathering costs increased in the period-to-period comparison due to higher transportation charges.The coal division includes thermal coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal division contributed$592 million of earnings before income tax from continuing operations for the year ended December 31, 2012 compared to $1,033 million for the year endedDecember 31, 2011. The total coal division sold 27.6 million tons of coal produced from continuing operations for the year ended December 31, 2012compared to 32.1 million tons for the year ended December 31, 2011.The average sales price and average costs per ton for continuing coal operations were as follows: For the Years Ended December 31, 2012 2011 Variance PercentChangeAverage Sales Price per ton sold$77.75 $90.10 $(12.35) (13.7)%Average Costs of Goods Sold per ton53.98 51.88 2.10 4.0 %Margin$23.77 $38.22 $(14.45) (37.8)%The lower average sales price per ton sold reflects a decrease in the global metallurgical coal markets, slightly offset by higher thermal coal averageprices as a result of several successful renegotiations of domestic thermal contracts where pricing took effect January 1, 2012. The coal division priced 7.5million tons on the export market at an average sales price of $83.67 per ton for the year ended December 31, 2012 compared to 9.7 million tons at an averageprice of $132.84 per ton for the year ended December 31, 2011. All other tons were sold on the domestic market. The decreased sales tonnage is primarily dueto decreased coal demand in both thermal and metallurgical markets and curtailed shipments due to the Bailey Belt incident in 2012, as discussed previously.Average costs per ton sold increased $2.10 per ton in the period-to-period comparison due primarily to the following:•Average cost of goods sold per ton increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.•The idled longwall at Buchanan Mine during portions of 2012 resulted in an increase in unit costs as the fixed costs were allocated over fewertons.•Average depreciation, depletion and amortization increased due to additional assets placed into service after the 2011 period.•Average operating supplies and maintenance costs per ton increased due to additional equipment maintenance, timing of major equipmentoverhaul costs, increased fuel and lubricants and use of pumpable cribs for roof support.•Average retirement and disability cost per ton decreased due to the improvement in other postretirement benefits discussed in the long-termliabilities section below.73The other segment includes industrial supplies activity, coal terminal activity, income taxes and other business activities not assigned to the gas or coalsegment.At the beginning of 2012, management decided that it would no longer consider general and administrative costs on a segment by segment basis as afactor in their decision making process. These decisions include allocation of capital and individual segment profit performance results. Management didconclude that general and administrative costs would continue to be considered in results at the divisional level (total gas and total coal). In order to presentfinancial information in a manner consistent with internal management's evaluations, the prior period general and administrative costs have been reclassified toreflect information consistent with the current year's presentation. The total divisional results have not changed. Individual segment results within the divisionhave been recast to reflect costs excluding general and administrative. General and administrative costs are excluded from the gas and coal unit costs above. Asin the prior periods, general and administrative costs are allocated between divisions (Gas, Coal, Other) based primarily on percentage of total revenue andpercentage of total projected capital expenditures. The total general and administrative costs were made up of the following items: For the Years Ended December 31, 2012 2011 Variance PercentChangeEmployee Wages and Related Expenses$35 $44 $(9) (20.5)%Advertising and Promotion4 7 (3) (42.9)%Consulting and Professional Services14 17 (3) (17.6)%Contributions9 10 (1) (10.0)%Miscellaneous17 19 (2) (10.5)%Total Company General and Administrative Expenses$79 $97 $(18) (18.6)%Total Company General and Administrative Expenses changed due to the following:•Employee wages and related expenses decreased $9 million primarily attributable to lower salary OPEB expenses in the period-to-period comparison.The lower expenses relate to changes in the discount rates and other assumptions, and a modification of the salaried other post-employment benefitplan. See Note 16—Pension and Other Postretirement Benefit Plans and Note 17—Coal Workers' Pneumoconiosis (CWP) and Workers'Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to totalCompany expense increases•Advertising and promotion decreased $3 million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising andpromotion campaign.•Consulting and professional services decreased $3 million in the period-to-period comparison due to various legal proceedings and corporateinitiatives, none of which were individually significant.•Contributions decreased $1 million in the period-to-period comparison due to various transactions, none of which were individually material.•Miscellaneous general and administrative expenses decreased $2 million in the period-to-period comparison due to various transactions throughoutboth periods, none of which were individually material.Total Company long-term liabilities, such as OPEB, the salary retirement plan, workers' compensation and long-term disability are actuariallycalculated for the Company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. TotalCONSOL Energy expense for continuing operations related to our actuarially calculated liabilities was $148 million for the year ended December 31, 2012compared to $176 million for the year ended December 31, 2011. The decrease was primarily due to a decrease in the discount rate assumptions used tocalculate expense for benefit plans at the measurement date, which is December 31. Additionally, a part of the decrease was due to a plan modification for thesalaried OPEB plan which required a remeasurement at March 31, 2012. See Note 16—Pension and Other Postretirement Benefit Plans and Note 17—CoalWorkers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K foradditional details related to total Company expense increases.74TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:The gas segment contributed $39 million to earnings before income tax for the year ended December 31, 2012 compared to $130 million for the yearended December 31, 2011. For the Year Ended Difference to Year Ended December 31, 2012 December 31, 2011 Marcellus CBM ShallowOil andGas OtherGas TotalGas Marcellus CBM ShallowOil andGas OtherGas TotalGasSales: Produced$134 $378 $135 $10 $657 $15 $(83) $(20) $(2) $(90)Related Party— 2 — — 2 — (3) — — (3)Total Outside Sales134 380 135 10 659 15 (86) (20) (2) (93)Gas Royalty Interest— — — 50 50 — — — (17) (17)Purchased Gas— — — 3 3 — — — (1) (1)Other Income— — — 57 57 — — — (2) (2)Total Revenue and OtherIncome134 380 135 120 769 15 (86) (20) (22) (113)Lifting12 37 40 2 91 (3) (3) (9) 1 (14)Ad Valorem,Severance, and OtherTaxes4 10 10 2 26 3 (2) (2) 1 —Gathering24 106 26 5 161 9 8 (1) 3 19Gas DirectAdministrative,Selling & Other17 14 13 3 47 6 (15) (8) 3 (14)Depreciation,Depletion andAmortization47 87 59 9 202 12 (14) (2) (1) (5)General &Administration— — — 40 40 — — — (11) (11)Gas Royalty Interest— — — 39 39 — — — (20) (20)Purchased Gas— — — 3 3 — — — (1) (1)Exploration and OtherCosts— — — 39 39 — — — 21 21Other CorporateExpenses— — — 77 77 — — — 12 12Interest Expense— — — 5 5 — — — (5) (5)Total Cost104 254 148 224 730 27 (26) (22) 3 (18)Earnings BeforeNoncontrolling Interest andIncome Tax30 126 (13) (104) 39 (12) (60) 2 (25) (95)Noncontrolling Interest— — — — — — — — (4) (4)Earnings (Loss) BeforeIncome Tax$30 $126 $(13) $(104) $39 $(12) $(60) $2 $(21) $(91)75MARCELLUS GAS SEGMENTThe Marcellus segment contributed $30 million to the total Company earnings before income tax for the year ended December 31, 2012 compared to $42million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangeMarcellus Gas Sales Volumes (Bcf)35.9 26.9 9.0 33.5 %NGLs Sales Volumes (Bcfe)*0.6 — 0.6 100.0 %Total Marcellus Gas Sales Volumes (Bcfe)*36.5 26.9 9.6 35.7 % Average Sales Price - Gas (Mcf)$2.89 $4.22 $(1.33) (31.5)%Hedging Impact - Gas (Mcf)$0.69 $0.21 $0.48 228.6 %Average Sales Price - NGLs (Mcfe)*$8.68 $— $8.68 100.0 %Average Sales Price - Condensate (Mcfe)*$13.54 $— $13.54 100.0 % Total Average Marcellus sales (per Mcfe)$3.68 $4.43 $(0.75) (16.9)%Average Marcellus lifting costs (per Mcfe)$0.34 $0.56 $(0.22) (39.3)%Average Marcellus ad valorem, severance, and other taxes (per Mcfe)$0.12 $0.05 $0.07 140.0 %Average Marcellus gathering costs (per Mcfe)$0.67 $0.54 $0.13 24.1 %Average Marcellus direct administrative, selling & costs (per Mcfe)$0.46 $0.41 $0.05 12.2 %Average Marcellus depreciation, depletion and amortization costs(per Mcfe)$1.30 $1.33 $(0.03) (2.3)% Total Average Marcellus costs (per Mcfe)$2.89 $2.89 $— — % Average Margin for Marcellus (per Mcfe)$0.79 $1.54 $(0.75) (48.7)%* NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and naturalgas,which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.The Marcellus segment sales revenues were $134 million for the year ended December 31, 2012 compared to $119 million for the year endedDecember 31, 2011. The $15 million increase was primarily due to a 35.7% increase in total sales volumes, offset, in part, by a 16.9% decrease in totalaverage sales price per Mcfe. The decrease in Marcellus average sales price was the result of the decline in general market prices; offset in part, by various gasswap transactions that matured in the year ended December 31, 2012. These gas swap transactions qualify as financial cash flow hedges that exist parallel tothe underlying physical transactions. These hedges represented approximately 12.4 Bcf of our produced Marcellus gas sales volumes for the year endedDecember 31, 2012 at an average price of $4.99 per Mcf. For the year ended December 31, 2011, these financial hedges represented 10.6 Bcf at an averageprice of $4.64 per Mcf. Marcellus sales volumes increased 9.6 Bcf due to our on-going drilling program.Total costs for the Marcellus Segment were $104 million for the year ended December 31, 2012 compared to $77 million for the year endedDecember 31, 2011. The average costs in the period-to-period comparison are discussed below.•Marcellus lifting costs were $12 million for the year ended December 31, 2012 compared to $15 million for the year ended December 31, 2011.Lifting costs decreased primarily due to lower well servicing costs, well tending costs and additional sales volumes during the 2012 year-to-date period. Theseimprovements, along with additional sales volumes resulted in a $0.22 improvement in average unit costs.•Marcellus ad valorem, severance, and other taxes were $4 million for the year ended December 31, 2012 compared to $1 million for the year endedDecember 31, 2011. The increase of $0.07 per Mcfe sold is primarily due to new legislation passed in the state of Pennsylvania (Act 13 of 2012, House Bill1950). This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within Pennsylvania. The impact on unitcosts of this increase was offset, in part, by higher volumes sold.•Marcellus gathering costs were $24 million for the year ended December 31, 2012 compared to $15 million for the year ended December 31, 2011.Average gathering costs increased $0.13 per Mcfe primarily due to increased firm76transportation usage and the formation of CONE Gathering LLC (CONE), a 50% owned affiliate. CONE began charging CONSOL Energy a fixed gatheringrate of $0.46 per MMbtu on Marcellus production volumes during the 4th quarter of 2011.•Marcellus direct administrative, selling & other costs were $17 million for the year ended December 31, 2012 compared to $11 million for the yearended December 31, 2011. Direct administrative, selling & other costs attributable to the total gas division are allocated to the individual gas segments basedon a combination of production and employee counts. The $6 million increase in period-to-period comparison is due to increased direct administrative laborand Marcellus volumes representing a larger portion of total natural gas volumes.•Depreciation, depletion and amortization costs were $47 million for the year ended December 31, 2012 compared to $35 million for the year endedDecember 31, 2011. There was approximately $44 million, or $1.24 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, 2012. There wasapproximately $27 million, or $1.04 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, 2011. 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. Additionally, there was approximately $3million, or $0.06 Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for theyear ended December 31, 2012. There was $8 million, or $0.29 per Mcf, of depreciation, depletion and amortization related to gathering and other equipmentreflected on a straight line basis for the year ended December 31, 2011. The decrease in Marcellus gathering and other equipment depreciation, depletion andamortization related to the sale if assets to CONE Gathering LLC (CONE), a 50% owned affiliate.COALBED METHANE (CBM) GAS SEGMENTThe CBM segment contributed $126 million to the total Company earnings before income tax for the year ended December 31, 2012 compared to $186million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangeCBM Gas Sales Volumes (Bcf)88.2 92.4 (4.2) (4.5)% Average Sales Price - Gas (Mcf)$2.88 $4.13 $(1.25) (30.3)%Hedging Impact - Gas (Mcf)$1.44 $0.92 $0.52 56.5 % Total Average CBM sales price (per Mcf)$4.32 $5.05 $(0.73) (14.5)%Average CBM lifting costs (per Mcf)$0.42 $0.43 $(0.01) (2.3)%Average CBM ad valorem, severance, and other taxes (per Mcf)$0.12 $0.13 $(0.01) (7.7)%Average CBM gathering costs (per Mcf)$1.21 $1.06 $0.15 14.2 %Average CBM direct administrative, selling & other costs (per Mcf)$0.16 $0.31 $(0.15) (48.4)%Average CBM depreciation, depletion and amortization costs (perMcf)$0.98 $1.10 $(0.12) (10.9)% Total Average CBM costs (per Mcf)$2.89 $3.03 $(0.14) (4.6)% Average Margin for CBM (per Mcf)$1.43 $2.02 $(0.59) (29.2)%CBM sales revenues were $380 million for the year ended December 31, 2012 compared to $466 million for the year ended December 31, 2011. The$86 million decrease was primarily due to a 14.5% decrease in average sales price per Mcf sold, offset, in part, by a 4.5% increase in average volumes sold.The decrease in CBM average sales price is the result of various gas swap transactions that matured in each period and lower average market prices. The gasswap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges representedapproximately 45.8 Bcf of our produced CBM gas sales volumes for the year ended December 31, 2012 at an average price of $5.34 per Mcf. For the yearended December 31, 2011, these financial hedges represented 61.8 Bcf at an average price of $5.36 per Mcf. CBM sales volumes decreased 4.2 Bcf primarilydue to normal well declines without a corresponding increase in77wells drilled and the impact on gas production from the idling of the Buchanan Mine during the 2012 period. The focus of the gas division is to develop itsMarcellus and Utica acreage.Total costs for the CBM segment were $254 million for the year ended December 31, 2012 compared to $280 million for the year ended December 31,2011. Lower costs in the period-to-period comparison are are discussed below. •CBM lifting costs were $37 million for the year ended December 31, 2012 compared to $40 million for the year ended December 31, 2011. The $3million decrease is primarily due to idle rig costs incurred during the 2011 period, reduced road maintenance costs, offset, in part, by increased slip repairs.•CBM ad valorem, severance, and other taxes were $10 million for the year ended December 31, 2012 compared to $12 million for the year endedDecember 31, 2011. The decrease in total dollars was primarily due to reduced severance tax expense caused by lower average gas sales price during 2012.These changes resulted in a $0.01 reduction to average units costs.•CBM gathering costs were $106 million for the year ended December 31, 2012 compared to $98 million for the year ended December 31, 2011.Higher CBM gathering units costs are related to increased compressor maintenance, additional equipment lease rentals and lower volumes sold in the period-to-period comparison.•CBM direct administrative, selling & other costs were $14 million for year ended December 31, 2012 compared to $29 million for the year endedDecember 31, 2011. Direct administrative, selling & other costs attributable to the total gas segment are allocated to the individual gas segments based on acombination of production and employee counts. The decrease in direct administrative, selling & other costs was primarily due to reduced directadministrative labor and CBM volumes representing a smaller portion of total natural gas volumes.•Depreciation, depletion and amortization attributable to the CBM segment was $87 million for the year ended December 31, 2012 compared to $101million for the year ended December 31, 2011. There was approximately $60 million, or $0.67 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 31,2012. The production portion of depreciation, depletion and amortization was $72 million, or $0.78 per unit-of-production in the year ended December 31,2011. The CBM unit-of-production rate decreased due to revised rates which are generally calculated using the net book value of assets divided by eitherproved or proved developed reserve additions. There was approximately $28 million, or $0.31 per Mcf of depreciation, depletion and amortization related togathering and other equipment reflected on a straight line basis for the year ended December 31, 2012. The non-production related depreciation, depletion andamortization was $29 million, or $0.32 per Mcf for the year ended December 31, 2011.78SHALLOW OIL AND GAS SEGMENTThe Shallow Oil and Gas segment had a loss before income tax of $13 million for the year ended December 31, 2012 compared to a loss before incometax of $15 million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangeShallow Oil and Gas Sales Volumes (Bcf)28.7 31.7 (3.0) (9.5)%Oil Sales Volumes (Bcfe)*0.5 0.5 — — %Total Shallow Oil and Gas Sales Volumes (Bcfe)*29.2 32.2 (3.0) (9.3)% Average Sales Price - Gas (Mcf)$3.12 $4.52 $(1.40) (31.0)%Hedging Impact - Gas (Mcf)$1.33 $0.16 $1.17 731.3 %Average Sales Price - Oil (Mcfe)*$15.65 $15.71 $(0.06) (0.4)% Total Average Shallow Oil and Gas sales price (per Mcfe)$4.64 $4.83 $(0.19) (3.9)%Average Shallow Oil and Gas lifting costs (per Mcfe)$1.37 $1.52 $(0.15) (9.9)%Average Shallow Oil and Gas ad valorem, Severance, and other taxes (per Mcfe)$0.35 $0.37 $(0.02) (5.4)%Average Shallow Oil and Gas gathering costs (per Mcfe)$0.92 $0.83 $0.09 10.8 %Average Shallow Oil and Gas direct administrative, selling & other costs (per Mcfe)$0.45 $0.67 $(0.22) (32.8)%Average Shallow Oil and Gas depreciation, depletion and amortization costs (perMcfe)$2.02 $1.90 $0.12 6.3 % Total Average Shallow Oil and Gas costs (per Mcfe)$5.11 $5.29 $(0.18) (3.4)% Average Margin for Shallow Oil and Gas (per Mcfe)$(0.47) $(0.46) $(0.01) 2.2 %*Oil, NGLs, and Condensate are converted to Mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil andnatural gas,which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.Shallow Oil and Gas sales revenues were $135 million for the year ended December 31, 2012 compared to $155 million for the year endedDecember 31, 2011. The $20 million decrease was primarily due to the 9.3% decrease in volumes sold as well as the 3.9% decrease in average sales price. Thedecrease in shallow oil and gas average sales price is the result of lower average market prices, offset, in part by various gas swap transactions that matured ineach period. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financialhedges represented approximately 18.5 Bcf of our produced Shallow Oil and Gas gas sales volumes for the year ended December 31, 2012 at an average priceof $5.23 per Mcf. For the year ended December 31, 2011, these financials hedges represented 11.5 Bcf at an average price of $4.97 per Mcf. Shallow oil andgas sales volumes decreased 3.0 Bcf primarily due to normal well declines without corresponding increase in wells drilled.The total costs for the shallow oil and gas segment were $148 million for the year ended December 31, 2012 compared to $170 million for the yearended December 31, 2011. Lower costs in the period-to-period comparison are discussed below.•Shallow Oil and Gas lifting costs were $40 million for the year ended December 31, 2012 compared to $49 million for the year ended December 31,2011. Lifting costs per unit decreased $0.15 per Mcfe sold primarily due to lower road maintenance, decreased well tending expenses and decreased swabbingand fishing expenses in the period-to-period comparison.•Shallow oil and gas ad valorem, severance, and other taxes were $10 million for the year ended December 31, 2012 compared to $12 million for theyear ended December 31, 2011. The decrease to total costs and average unit costs was primarily due to reduced severance tax expense caused by lower averagegas sales prices during 2012.•Shallow Oil and Gas gathering costs were $26 million for the year ended December 31, 2012 compared to $27 million for the year endedDecember 31, 2011. Gathering costs decreased primarily due to lower compressor maintenance and lower79equipment lease expense in the period-to-period comparison. The impact of these reductions on unit costs was offset by lower sales volumes.•Shallow Oil and Gas direct administrative, selling and other costs were $13 million for the year ended December 31, 2012 compared to $21 millionfor the year ended December 31, 2011. Direct administrative, selling and other costs attributable to the total gas segment are allocated to the individual gassegments based on a combination of production and employee counts. The $8 million decrease in the period-to-period comparison is due to reduced directadministrative labor and Shallow Oil and Gas volumes representing a smaller proportion of total natural gas volumes.•Depreciation, depletion and amortization costs were $59 million for the year ended December 31, 2012 compared to $61 million for the year endedDecember 31, 2011. There was approximately $51 million, or $1.75 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, 2012. There wasapproximately $54 million, or $1.67 per unit-of-production, of depreciation, depletion and amortization related to Shallow Oil and Gas gas and related wellequipment that was reflected on a units-of-production method of depreciation for the year ended December 31, 2011. The rate was calculated by taking the netbook value of the related assets divided by either proved or proved developed reserves, generally at the previous year end. There was approximately $8 million,or $0.27 per Mcf, of depreciation, depletion and amortization related to gathering and other equipment that was reflected on a straight line basis for the yearended December 31, 2012. There was $7 million, or $0.23 per Mcf, of depreciation, depletion and amortization related to gathering and other equipmentreflected on a straight line basis for the year ended December 31, 2011. The increase was related to additional infrastructure and equipment placed in serviceafter the 2012 period.OTHER GAS SEGMENTThe other gas segment includes activity not assigned to the Marcellus, CBM, or shallow oil & 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$10 million for the year ended December 31, 2012 and $12 million for the year ended December 31, 2011. Total costs related to these other sales were $21million for the 2012 period and were $14 million for the 2011 period. The increase in costs in the period-to-period comparison were primarily attributable toincreased gathering and direct administrative, selling & other costs relating to the Utica operating area during 2012. 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 $50 million for the year ended December 31, 2012 compared to $67 million for the year endedDecember 31, 2011. 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, 2012 2011 Variance PercentChangeGas Royalty Interest Sales Volumes (Bcf)18.0 16.4 1.6 9.8 %Average Sales Price (per Mcf)$2.74 $4.07 $(1.33) (32.7)%Purchased gas sales volumes represent volumes of gas sold at market prices that were purchased from third-party producers. Purchased gas salesrevenues were $3 million for the year ended December 31, 2012 compared to $4 million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangePurchased Gas Sales Volumes (Bcf)1.1 1.0 0.1 10.0 %Average Sales Price (per Mcf)$3.03 $4.28 $(1.25) (29.2)%Other income was $57 million for the year ended December 31, 2012 compared to $59 million for the year ended December 31, 2011. The $2 milliondecrease was primarily due to the following items.80•Gain on sale of assets decreased $30 million due to gains on the Hess transaction and Antero overriding royalty interest of $53 million and $41million respectively, both of which occurred in 2011. Additionally, CONSOL Energy incurred a $64 million loss on the Noble transactionduring 2011.•Interest income increased $20 million due to the notes receivable which were part of the Noble joint venture transaction.•Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% owned affiliate. CONE was formed in relation to theNoble joint venture transaction.•The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.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 $39 million for the year ended December 31, 2012 compared to $59 million for the year ended December 31,2011. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed tothe period-to-period change. For the Years Ended December 31, 2012 2011 Variance PercentChangeGas Royalty Interest Sales Volumes (Bcf)18.0 16.4 1.6 9.8 %Average Sales Price (per Mcf)$2.16 $3.61 $(1.45) (40.2)%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 Mcf is due to overall price changes and contractual differences among customers in the period-to-periodcomparison. Purchased gas costs were $3 million for the year ended December 31, 2012 compared to $4 million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangePurchased Gas Volumes (Bcf)1.1 1.2 (0.1) (8.3)%Average Sales Price (per Mcf)$2.44 $3.07 $(0.63) (20.5)%Exploration and other costs were $39 million for the year ended December 31, 2012 compared to $18 million for the year ended December 31, 2011.The $21 million increase in costs is primarily related to the following items: For the Years Ended December 31, 2012 2011 Variance PercentChangeLease Expiration Costs$18 $6 $12 200.0 %Marcellus Title Defects4 — $4 100.0 %Exploration Costs14 7 7 100.0 %Dry Hole Costs3 5 (2) (40.0)%Total Exploration and Other Costs$39 $18 $21 116.7 %•Lease expiration costs increased $12 million primarily due to lease expirations where CONSOL Energy allowed primary lease terms to expire.•CONSOL Energy reviewed title defect notices, asserted by Noble, and working in collaboration with Noble, conceded title defects on acreage whichhad a carrying value to CONSOL Energy of $4 million for the year ended December 31, 2012.•Exploration expense increased $7 million due to higher exploratory expenses associated with the Utica operating area and various other transactionsthat occurred throughout both periods, none of which were individually material.•Dry Hole Costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.Other corporate expenses were $77 million for the year ended December 31, 2012 compared to $65 million for the year ended December 31, 2011. The$12 million increase in the period-to-period comparison was made up of the following items:81 For the Years Ended December 31, 2012 2011 Variance PercentChangeLegal Fees$5 $— $5 100.0%PA Impact Fees4 — 4 100.0%Unused FT Commitments16 14 2 14.3%Short-term incentive compensation26 25 1 4.0%Stock-based compensation18 18 — —%Bank fees7 7 — —%Other1 1 — —%Total Other Corporate Expenses$77 $65 $12 18.5%•Legal fees were related to CNX Gas royalty litigation and title defect work, as previously discussed.•PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the firstquarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. Aspart of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to2012. The $4 million represents the one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate tocurrent year wells drilled, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.•Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flowuninterrupted as the gas operations continue to increase sales volumes.•The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches 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 2012 period and an increased allocation of expense from CONSOL Energy as a result of exceeding corporate targets.•Stock-based compensation remained consistent in the period-to-period comparison. Stock-based compensation costs are allocated to the gas segmentbased on revenue and capital expenditure projections between coal and gas.•Bank fees remained consistent in the period-to-period comparison.•Other corporate related expense remained consistent in the period-to-period comparison.Interest expense related to the other gas segment was $5 million for the year ended December 31, 2012 compared to $10 million for the year endedDecember 31, 2011. 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 $5 million decrease was primarily due to lower levels of borrowings on the revolving credit facility in the period-to-period comparison.Noncontrolling interest represents 100% of earnings impact of a third party in which CONSOL Energy held no ownership interest. The variance in thenoncontrolling amounts reflects the third parties variance in earnings in the period-to-period comparison. In the year ended December 31, 2011, the drillingservices contract was bought out. Subsequent to this transaction, the noncontrolling interest was de-consolidated.82TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:The coal segment contributed $592 million of earnings before income tax in the year ended December 31, 2012 compared to $1,033 million in the yearended December 31, 2011. For the Year Ended Difference to Year Ended December 31, 2012 December 31, 2011 ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoal ThermalCoal HighVolMetCoal LowVolMetCoal OtherCoal TotalCoalSales: Produced Coal$1,431 $210 $506 $5 $2,152 $(65) $(114) $(566) $(22) $(767)Purchased Coal— — — 17 17 — — — (23) (23)Total Outside Sales1,431 210 506 22 2,169 (65) (114) (566) (45) (790)Freight Revenue— — — 107 107 — — — (69) (69)Other Income2 6 — 324 332 (4) (5) — 269 260Total Revenue and OtherIncome1,433 216 506 453 2,608 (69) (119) (566) 155 (599)Costs and Expenses: Beginning inventorycosts67 2 16 — 85 (17) 2 6 — (9)Total direct costs593 95 184 145 1,017 37 (14) (14) 16 25Total royalty/productiontaxes74 9 30 3 116 (10) (3) (37) (5) (55)Total direct services tooperations154 21 22 217 414 (71) (21) (24) 57 (59)Total retirement anddisability61 10 28 20 119 (11) (6) (10) 6 (21)Depreciation, depletionand amortization120 22 37 33 212 (7) (5) — 12 —Ending inventory costs(33) — (21) — (54) 35 — (5) — 30Total Costs and Expenses1,036 159 296 418 1,909 (44) (47) (84) 86 (89)Freight Expense— — — 107 107 — — — (69) (69)Total Costs1,036 159 296 525 2,016 (44) (47) (84) 17 (158)Earnings (Loss) BeforeIncome Taxes$397 $57 $210 $(72) $592 $(25) $(72) $(482) $138 $(441)83THERMAL COAL SEGMENTThe thermal coal segment contributed $397 million to total Company earnings before income tax for the year ended December 31, 2012 compared to$422 million for the year ended December 31, 2011. The thermal coal revenue and cost components on a per unit basis for these periods are as follows: For the Years Ended December 31, 2012 2011 Variance PercentChangeCompany Produced Thermal Tons Sold (in millions)20.7 22.4 (1.7) (7.6%)Average Sales Price Per Thermal Ton Sold$69.08 $66.84 $2.24 3.4% Beginning Inventory Costs Per Thermal Ton$61.92 $53.42 $8.50 15.9% Total Direct Operating Costs Per Thermal Ton Produced$29.29 $25.35 $3.94 15.5%Total Royalty/Production Taxes Per Thermal Ton Produced3.65 3.82 (0.17) (4.5%)Total Direct Services to Operations Per Thermal Ton Produced7.61 10.25 (2.64) (25.8%)Total Retirement and Disability Per Thermal Ton Produced3.01 3.28 (0.27) (8.2%)Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced5.93 5.76 0.17 3.0% Total Production Costs Per Thermal Ton Produced$49.49 $48.46 $1.03 2.1% Ending Inventory Costs Per Thermal Ton$(50.89) $(61.92) $11.03 17.8% Total Costs Per Thermal Ton Sold$50.00 $48.25 $1.75 3.6% Average Margin Per Thermal Ton Sold$19.08 $18.59 $0.49 2.6%Thermal coal revenue was $1,431 million for the year ended December 31, 2012 compared to $1,496 million for the year ended December 31, 2011.The $65 million decrease was attributable to 1.7 million fewer tons sold in 2012 partially offset by a $2.24 per ton higher average sales price. The higheraverage thermal coal sales price in the 2012 period was the result of the successful renegotiations of several domestic thermal contracts during the period. Thethermal coal segment was also impacted by 2.1 million tons of thermal coal sold on the high volatile metallurgical coal market for the year ended December 31,2012, which was 0.7 million tons more than the tons sold in the year ended December 31, 2011.Other income attributable to the thermal coal segment represents earnings from our equity affiliates that operate thermal coal mines. The equity inearnings of affiliates is insignificant to the total segment activity.Total costs of goods sold are comprised of changes in thermal coal inventory, both volumes and carrying values, and costs of tons produced in theperiod. Total cost of goods sold for thermal coal was $1,036 million for the year ended December 31, 2012, or $44 million lower than the $1,080 million forthe year ended December 31, 2011. Although total cost of goods sold dollars were improved, total costs per ton sold on a unit basis were impaired. Total costof goods sold for thermal coal was $50.00 per ton in the year ended December 31, 2012 compared to $48.25 per ton in the year ended December 31, 2011. Theincrease in costs of goods sold per thermal ton was due to the items described below.Direct operating costs related to the thermal coal segment were $593 million for the year ended December 31, 2012 compared to $556 million for theyear ended December 31, 2011. Direct operating costs were $29.29 per ton produced in the current year compared to $25.35 per ton produced in the prioryear. Changes in the average direct operating costs per thermal ton produced were primarily related to the following items:•Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 20.3 million tons in 2012 comparedto 21.9 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.•Average operating supplies and maintenance costs per ton increased due to additional maintenance and equipment overhaul costs and additionalcontractor labor, combined with lower tons produced. Additional maintenance and equipment overhaul costs are related to additional equipmentbeing serviced in the current year. Additional contractor84labor costs resulted from additional underground hourly contractors utilized as well as additional security contractor costs in the current year.•The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-periodcomparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall averagedirect operating costs per ton produced.•There were no significant changes in various other unit costs individually or in total.Royalties and production taxes decreased $10 million to $74 million in the current year. Average cost per thermal ton produced decreased $0.17 per tondue to a change in the mix of coal produced both geographically and in ownership, which changed the production tax and royalty rates, respectively.Direct service costs were $154 million in the current year compared to $225 million in the prior year. Direct services to the operations were $7.61 perton in the current year compared to $10.25 per ton in the prior year. Changes in the average direct service to operations cost per thermal ton produced wereprimarily related to the following items:•Average direct service costs to operations were impaired due to lower tons produced in the year-to-year comparison.•Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds andditches, and additional permits for water discharge pipelines.•Selling expense decreased in the year-to-year comparison due to fewer tons being sold under contracts that require commissions.Retirement and disability costs attributable to the thermal coal segment were $61 million for the year ended December 31, 2012 compared to $72 millionfor the year ended December 31, 2011. The decrease in the thermal coal retirement and disability costs was primarily attributable to a change in discount ratesused to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirement benefit plan. These improvements were offset, inpart, by the reduction in production volumes which negatively impacted unit costs.Depreciation, depletion and amortization for the thermal coal segment was $120 million for the year ended December 31, 2012 compared to $127 millionfor the year ended December 31, 2011. The decrease was primarily due to lower depletion directly related to lower production volumes. Unit costs per thermalton produced were higher for the year ended December 31, 2012 compared to the year ended December 31, 2011 due to additional equipment and infrastructureplaced into service after the 2011 year that is depreciated on a straight-line basis.Changes in thermal coal inventory volumes and carrying value, resulted in $34 million of costs of goods sold for the year ended December 31, 2012compared to $16 million for the year ended December 31, 2011. Thermal coal inventory was 0.6 million tons at December 31, 2012 compared to 1.1 milliontons at December 31, 2011.85HIGH VOL METALLURGICAL COAL SEGMENTThe high volatile metallurgical coal segment contributed $57 million to total Company earnings before income tax for the year ended December 31, 2012compared to $129 million for the year ended December 31, 2011. 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, 2012 2011 Variance PercentChangeCompany Produced High Vol Met Tons Sold (in millions)3.3 4.1 (0.8) (19.5%)Average Sales Price Per High Vol Met Ton Sold$63.93 $78.57 $(14.64) (18.6%) Beginning Inventory Costs Per High Vol Met Ton$— $— $— —% Total Direct Operating Costs Per High Vol Met Ton Produced$28.98 $26.41 $2.57 9.7%Total Royalty/Production Taxes Per High Vol Met Ton Produced2.72 2.86 (0.14) (4.9%)Total Direct Services to Operations Per High Vol Met Ton Produced6.22 10.23 (4.01) (39.2%)Total Retirement and Disability Per High Vol Met Ton Produced3.10 3.87 (0.77) (19.9%)Total Depreciation, Depletion and Amortization Costs Per High Vol MetTon Produced6.63 6.55 0.08 1.2% Total Production Costs Per High Vol Met Ton Produced$47.65 $49.92 $(2.27) (4.5%) Ending Inventory Costs Per High Vol Met Ton$— $— $— —% Total Costs Per High Vol Met Ton Sold$48.43 $49.89 $(1.46) (2.9%) Margin Per High Vol Met Ton Sold$15.50 $28.68 $(13.18) (46.0%)High volatile metallurgical coal revenue was $210 million for the year ended December 31, 2012 compared to $324 million for the year endedDecember 31, 2011. Average sales prices for high volatile metallurgical coal decreased $14.64 per ton in the year-to-year comparison due to a weakening inglobal metallurgical coal demand. CONSOL Energy priced 2.7 million tons of high volatile metallurgical coal in the export market at an average sales price of$60.75 per ton for the year ended December 31, 2012 compared to 3.8 million tons at an average price of $78.05 per ton for the year ended December 31,2011. The remaining tons sold in the year-to-year comparison were sold in the domestic market.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.Total cost of goods sold are comprised of changes in high volatile metallurgical coal inventory and costs of tons produced in the period. Total cost ofgoods sold for high volatile metallurgical coal was $159 million for the year ended December 31, 2012 or $47 million lower than the $206 million for the yearended December 31, 2011. Total cost of goods sold for high volatile metallurgical coal were $48.43 per ton in the year ended December 31, 2012 compared to$49.89 per ton in the year ended December 31, 2011. The decrease in cost of goods sold per high volatile metallurgical ton was due to the items describedbelow.Direct operating costs related to the high volatile metallurgical coal segment were $95 million in the year ended December 31, 2012 compared to $109million in the year ended December 31, 2011. Direct operating costs dollars are improved due to lower tons produced in the year-to-year comparison and due tocost control measures that were implemented. Direct operating costs were $28.98 per ton produced in the current year compared to $26.41 per ton produced inthe prior year-to-date period. Changes in the average direct operating costs per high volatile metallurgical ton produced were primarily related to the followingitems:•Labor and related benefits average costs per high volatile metallurgical ton produced decreased due to less overtime worked, offset, in part, by lowertons produced and higher hourly wage rates.•Mine maintenance and supplies per ton produced decreased due to the mix of mines producing tons that were shipped as high volatile metallurgicalcoal. Mines with lower cost structures produced a larger portion of the high volatile metallurgical coal shipped in the current year compared to theprior year.86•Various other unit costs including power and miscellaneous costs did not change significantly individually or in total.•Improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.Royalties and production taxes were $9 million in the current year compared to $12 million in the prior year. The $3 million improvement was due tolower volumes and lower average sales prices. High volatile metallurgical coal royalties and production taxes were $2.72 per ton in the current year compared to$2.86 per ton in the prior year. Average cost per high volatile metallurgical ton produced decreased due to a change in the mix of coal produced bothgeographically and in ownership, which changed the production tax and royalty rates, respectively.Direct service costs for high volatile metallurgical coal were $21 million in the current year compared to $42 million in the prior year. Lower costs wereattributable to fewer tons subject to commission expense, lower direct administrative costs, and lower subsidence costs. Direct services to the operations forhigh volatile metallurgical coal were $6.22 per ton in the current year compared to $10.23 per ton in the prior year. Changes in the average direct service tooperations cost per ton for high volatile metallurgical coal produced were primarily related to a reduction of commission rates due to a decrease in the averagesales price.Retirement and disability costs attributable to the high volatile metallurgical coal segment were $10 million for the year ended December 31, 2012compared to $16 million for the year ended December 31, 2011. The decrease in the high volatile metallurgical coal retirement and disability costs wasprimarily attributable to a change in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirementbenefit plan. These improvements were offset, in part, by the reduction in production volumes which negatively impacted unit costs.Depreciation, depletion and amortization for the high volatile metallurgical coal segment was $22 million for the year ended December 31, 2012compared to $27 million for the year ended December 31, 2011. The decrease was primarily due to lower depletion directly related to lower productionvolumes. Unit costs per high volatile ton produced were higher in the year ended December 31, 2012 compared to the year ended December 31, 2011 due toadditional equipment and infrastructure placed into service after the 2011 year that was depreciated on a straight-line basis.There were no changes in volumes or carrying value of coal inventory in the year ended December 31, 2012 and December 31, 2011. There was no highvolatile metallurgical coal inventory at December 31, 2012 or December 31, 2011.87LOW VOL METALLURGICAL COAL SEGMENTThe low volatile metallurgical coal segment contributed $210 million to total Company earnings before income tax in the year ended December 31, 2012compared to $692 million in the year ended December 31, 2011. 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, 2012 2011 Variance PercentChangeCompany Produced Low Vol Met Tons Sold (in millions)3.6 5.6 (2.0) (35.7%)Average Sales Price Per Low Vol Met Ton Sold$140.11 $191.81 $(51.70) (27.0%) Beginning Inventory Costs Per Low Vol Met Ton$67.60 $62.51 $5.09 8.1% Total Direct Operating Costs Per Low Vol Met Ton Produced$50.88 $34.90 $15.98 45.8%Total Royalty/Production Taxes Per Low Vol Met Ton Produced8.33 11.74 (3.41) (29.0%)Total Direct Services to Operations Per Low Vol Met Ton Produced6.03 8.15 (2.12) (26.0%)Total Retirement and Disability Per Low Vol Met Ton Produced7.63 6.71 0.92 13.7%Total Depreciation, Depletion and Amortization Costs Per Low Vol MetTon Produced10.23 6.54 3.69 56.4% Total Production Costs Per Low Vol Met Ton Produced$83.10 $68.04 $15.06 22.1% Ending Inventory Costs Per Low Vol Met Ton$(86.38) $(67.60) $(18.78) (27.8%) Total Costs Per Low Vol Met Ton Sold$81.89 $67.90 $13.99 20.6% Margin Per Low Vol Met Ton Sold$58.22 $123.91 $(65.69) (53.0%)Low volatile metallurgical coal revenue was $506 million for the year ended December 31, 2012 compared to $1,072 million for the year endedDecember 31, 2011. The $566 million decrease was attributable to a $51.70 per ton lower average sales price and nearly two million less tons sold. Averagesales prices for low volatile metallurgical coal decreased in the year-to-year comparison due to the weakening in global metallurgical coal demand. For the yearended December 31, 2012, 2.6 million tons of low volatile metallurgical coal was priced on the export market at an average price of $125.73 per ton comparedto 4.6 million tons at an average price of $196.46 per ton for the 2011 year. The remaining tons sold in the year-to-year comparison were sold on the domesticmarket.Total cost of goods sold are comprised of changes in low volatile metallurgical coal inventory and costs of tons produced in the period. Total cost ofgoods sold for low volatile metallurgical coal was $296 million for the year ended December 31, 2012, or $84 million lower than the $380 million for the yearended December 31, 2011. Total cost of goods sold for low volatile metallurgical coal was $81.89 per ton for the year ended December 31, 2012 compared to$67.90 per ton for the year ended December 31, 2011. The increase in cost of goods sold per low volatile metallurgical ton was due to the items describedbelow.Direct operating costs related to the low volatile metallurgical coal segment were $184 million for the year ended December 31, 2012 compared to $198million for the year ended December 31, 2011. Direct operating costs dollars are improved $14 million due to lower tons produced in the year-to-yearcomparison and cost control measures implemented, however, the cost improvements did not offset the impact of reduced production on unit costs. Directoperating costs were $50.88 per ton produced in the current year compared to $34.90 per ton produced in the prior year. Changes in the average directoperating costs per low volatile ton produced were primarily related to the following items:•The Buchanan longwall was idled during the months of March, April and October of 2012 which resulted in higher direct operating costs produced.The mine continued to run the continuous miners and perform mine maintenance during the months when the longwall was idled. This negativelyimpacted unit costs.•Low volatile metallurgical coal production was 3.7 million tons for the year ended December 31, 2012 compared to 5.7 million tons for the yearended December 31, 2011. Production was significantly lower in the year-to-year comparison due to the Buchanan Mine being idled for portions of2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Late in 2012, a five day work week instead of thenormal seven88day work week was implemented. Fixed costs were then spread over fewer tons produced which increased all costs on a per unit basis.Royalties and production taxes improved $37 million to $30 million in the current year-to-date period compared to $67 million in the prior year-to-dateperiod. Unit costs also improved $3.41 per low volatile metallurgical ton produced to $8.33 per ton in the current year-to-date period compared to $11.74 perton in the prior year-to-date period. Average cost per low volatile metallurgical ton produced decreased due to lower royalties and lower production taxes. Thesedecreases were related to lower volumes produced and lower average sales prices.Direct service costs for low volatile metallurgical coal were $22 million in the current year compared to $46 million in the prior year. Direct services tothe operations for low volatile metallurgical coal were $6.03 per ton in the current year compared to $8.15 per ton in the prior year. Changes in the averagedirect service to operations cost per ton for low volatile metallurgical coal produced were primarily related to lower tons of coal produced in the period-to-periodcomparison.Retirement and disability costs attributable to the low volatile metallurgical coal segment were $28 million for the year ended December 31, 2012compared to $38 million for the year ended December 31, 2011. The decrease in the low volatile metallurgical coal retirement and disability costs wasprimarily attributable to a decrease in discount rates used to calculate the cost of the long-term liabilities and a modification of the salaried other post-retirementbenefit plan. This improvement was offset, in part, by the reduction in production volumes which negatively impacted unit costs.Depreciation, depletion and amortization for the low volatile metallurgical coal segment was $37 million for both the years ended December 31, 2012 and2011. Unit costs per low volatile metallurgical ton produced were higher in the year ended December 31, 2012 compared to the year ended December 31, 2011due to lower volumes produced.Changes in low volatile metallurgical coal inventory volumes and carrying value resulted in $5 million of cost of goods sold in the year endedDecember 31, 2012 compared to $6 million of cost of goods sold in the year ended December 31, 2011. Produced low volatile metallurgical coal inventory was0.2 million tons at December 31, 2012 and December 31, 2011.OTHER COAL SEGMENTThe other coal segment had a loss before income tax of $72 million for the year ended December 31, 2012 compared to a loss before income tax of $210million for the year ended December 31, 2011. 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.The other coal segment produced coal sales includes revenue from the sale of 0.1 million tons of coal which was recovered during the reclamationprocess at idled facilities for the year ended December 31, 2012 compared to 0.4 million tons for the year ended December 31, 2011. The primary focus of theactivity at these locations is reclaiming disturbed land in accordance with the mining permit requirements after final mining has occurred. The tons sold areincidental to total 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 and coal purchased from third parties and sold directly to our customers. The revenues were $17 million for the year ended December 31, 2012compared to $40 million for the year ended December 31, 2011. The decrease was primarily due to increased volumes sold partially offset by a decrease in theaverage 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 $107 million for the year ended December 31, 2012 compared to$176 million for the year ended December 31, 2011. The $69 million decrease in freight revenue was due to decreased shipments where CONSOL Energycontractually provides transportation services.Miscellaneous other income was $324 million for the year ended December 31, 2012 compared to $55 million for the year ended December 31, 2011.The $269 million increase is due to the following items:•Gain on sale of assets attributable to the Other Coal segment were $271 million for the year ended December 31, 2012 compared to $5 million for theyear ended December 31, 2011. The change was primarily related to sales of non-producing assets in the Northern Powder River Basin that resultedin income of $151 million, as well as coal and surface lands in Western Canada, Illinois and West Virginia that resulted in income of $112 million.See Note 3—89Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail ofthese sales. The remaining $3 million change was related to various transactions that occurred throughout both periods, none of which wereindividually material.•For the year ended December 31, 2012, $12 million of income was recognized related to contracts from certain thermal coal customers that wereunable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from therequirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2011.•Gain on issuances of pipeline right-of-ways to third parties decreased $8 million in the year-to-year comparison, primarily due to a $10 millionpipeline right-of-way to a third party issued in the year ended December 31, 2011.•The remaining $1 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.Other coal segment total costs were $525 million for the year ended December 31, 2012 compared to $508 million for the year ended December31, 2011. The increase of $17 million was due to the following items: For the Years Ended December 31, 2012 2011 VarianceClosed and idle mines $134 $73 $61Bailey Belt Incident 42 — 42Voluntary Incentive Separation Program 13 — 13Litigation Contingencies 17 12 5General and Administrative Expense 102 123 (21)Purchased Coal 41 63 (22)Freight expense 107 175 (68)Other 69 62 7 Total other coal segment costs $525 $508 $17•Closed and idle mine costs increased approximately $61 million for the year ended December 31, 2012 compared to the year ended December 31,2011. The increase was the result of $30 million additional costs related to reclamation liabilities and on-going idling costs incurred at the FolaComplex for the year ended December 31, 2012. Closed and idle mine costs increased $20 million as the result of a 2012 decision to temporarily idleBuchanan Mine in 2012. Closed and idle mine costs increased $11 million due to other changes in the operational status of various other mines,between idled and operating throughout both periods, none of which were individually material.•Bailey Belt incident costs represents expenses related to continued advancement of the mines and on-going projects at the mines that took place duringthe idled phase when belt reconstruction was occurring.•In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation supportemployees with 30 years of service, or more. Under this program, eligible employees who accepted the offer will receive a severance payment equal toone year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program.Severance and vacation pay was approximately $13 million and was recognized for the year ended December 31, 2012. This was paid in January2013.•Litigation contingencies increased $5 million in the year-to-year comparison due to various items. See Note 24-Commitments and ContingentLiabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Companyexpense.•General and Administrative Expense related to the other coal segment decreased by $21 million primarily due to a reduction of wages and relatedexpenses.•Purchased coal costs decreased approximately $22 million in the year-to-year comparison primarily due to differences in the quality of coalpurchased, decreases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.•Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by 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 $68 million decrease in freight revenue was due todecreased shipments which CONSOL Energy contractually provides transportation services.•Other costs related to the coal segment increased $7 million due to various other transactions that occurred throughout both periods, none of whichare individually material.90OTHER SEGMENT ANALYSIS for the year ended December 31, 2012 compared to the year ended December 31, 2011:The other segment includes activity from the sales of industrial supplies, coal terminal operations and various other corporate activities that are notallocated to the gas or coal segment. The other segment had a loss before income tax of $224 million for the year ended December 31, 2012 compared to a lossbefore income tax of $289 million for the year ended December 31, 2011. The other segment also includes total company income tax expense of $89 millionfor the year ended December 31, 2012 compared to $191 million for the year ended December 31, 2011. For the Years Ended December 31, 2012 2011 Variance PercentChangeSales—Outside$294 $285 $9 3.2 %Other Income6 8 (2) (25.0)%Total Revenue300 293 7 2.4 %Cost of Goods Sold and Other Charges289 320 (31) (9.7)%Depreciation, Depletion & Amortization15 12 3 25.0 %Taxes Other Than Income Tax5 11 (6) (54.5)%Interest Expense215 239 (24) (10.0)%Total Costs524 582 (58) (10.0)%Loss Before Income Tax(224) (289) 65 22.5 %Income Tax89 191 (102) (53.4)%Net Loss$(313) $(480) $167 34.8 %Industrial supplies:Total revenue from industrial supplies was $244 million for the year ended December 31, 2012 compared to $236 million for the year endedDecember 31, 2011. The increase was related to higher sales volumes.Total costs related to industrial supply sales were $239 million for the year ended December 31, 2012 compared to $235 million for the year endedDecember 31, 2011. The increase of $4 million was primarily related to higher sales volumes and various changes in inventory costs, none of which wereindividually material.Transportation operations:Total revenue from transportation operations was $52 million for the year ended December 31, 2012 compared to $51 million for the year endedDecember 31, 2011. The increase of $1 million was primarily due to an increase in thru-put rates at the CNX Marine Terminal.Total costs related to the transportation operations were $43 million for the year ended December 31, 2012 compared to $36 million for the year endedDecember 31, 2011. The increase of $7 million was primarily attributable to an increase in thru-put costs at the CNX Marine Terminal offset, in part, by adecrease in thru-put tons.Miscellaneous other:Additional other income of $4 million was recognized for the year ended December 31, 2012 compared to $6 million for the year ended December 31,2011. The $2 million decrease was primarily due to various transactions that have occurred throughout both periods, none of which were individuallymaterial.Other corporate costs in the other segment include interest expense, transaction and financing fees and various other miscellaneous corporate charges.Total other costs were $242 million for the year ended December 31, 2012 compared to $311 million for the year ended December 31, 2011. Other corporatecosts decreased due to the following items:91 For the Years Ended December 31, 2012 2011 VarianceInterest expense $215 $239 $(24)Loss on extinguishment of debt — 16 (16)Transaction and financing fees — 15 (15)Bank fees 13 18 (5)Evaluation fees for non-core asset dispositions 4 6 (2)Other 10 17 (7) $242 $311 $(69)•Interest Expense decreased $24 million in the period-to-period comparison. Interest expense decreased due to an increase in capitalized interest relatedto higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $310 million inthe period-to-period comparison.•On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordancewith the terms of the indenture governing these notes.•The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held tomaturity.•Transaction and financing fees of $15 million incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-termbonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.•Bank fees decreased $5 million mainly due to lower borrowings on the revolving credit facilities in the period-to-period comparison and also due tothe refinancing and extension of the credit facility on April 12, 2011.•Evaluation fees for non-core asset dispositions and other legal charges decreased $2 million in the period-to-period comparison due to variouscorporate initiatives.•Various other corporate expenses decreased $7 million due to various transactions that occurred throughout both periods, none of which wereindividually material.Income Taxes:The effective income tax rate from continuing operations was 21.8% for the year ended December 31, 2012 compared to 21.9% for the year endedDecember 31, 2011. The decrease in the effective tax rate for the year ended December 31, 2012 as compared to the year ended December 31, 2011 wasprimarily attributable to various discrete transactions that occurred in both periods. The discrete transactions included an Internal Revenue Service auditsettlement for years 2006 and 2007 and the corresponding impacts to the previously accrued tax positions which resulted in higher percentage depletiondeductions. Discrete transactions also included the reversal of a valuation allowance for certain state net operating loss carryforwards and future temporarydeductions as well as the reversal of certain uncertain tax positions. See Note 7—Income Taxes in the Notes to the Audited Consolidated Financial Statementsin Item 8 of this Form 10-K for additional information. For the Years Ended December 31, 2012 2011 Variance PercentChangeTotal Company Earnings Before Income Tax$407 $873 $(466) (53.4)%Income Tax Expense$89 $191 $(102) (53.3)%Effective Income Tax Rate21.8% 21.9% (0.1)% 92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. We base our estimateson historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis formaking the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates on an on-going basis. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilizedare reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of theConsolidated Financial Statements.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 or non-represented hourly employees hired before January 1, 2007, the eligibility requirement is either age 55with 20 years of service or age 62 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 increasesof up to 6% will be shared by CONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of6% will be the responsibility of the participants. In addition, any salaried or non-represented hourly employees that were hired or rehired effective January 1,2007 or later and do not work in a corporate or operational support position are not eligible for retiree health benefits. In lieu of traditional retiree healthcoverage, if certain eligibility requirements are met, these employees will receive a retiree medical spending allowance of $2,250 per year for each year ofservice at retirement.On March 31, 2012, the salaried OPEB plan was amended to reduce medical and prescription drug benefits as of January 1, 2014. The planamendment calls for a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The amount of the contributionwill be dependent on several factors, and the money in the account can be used to help pay for a commercial medical plan, Medicare Part B or Part Dpremiums, and other qualified medical expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug benefits described above uponmeeting the eligibility requirements at retirement. Employees who work or worked in corporate or operational support positions who are under age 50 atDecember 31, 2013 will receive no retiree medical or prescription drug benefits.On December 5, 2013, the OPEB obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries (comprised of five WestVirginia Coal Mines, the River Division and various other locations) to Murray Energy. The OPEB obligation was reduced by $1,891.1 million. The planwas remeasured on the date of the sale using a discount rate of 4.91% compared to December 31, 2012 discount rate of 4.05% .As of December 31, 2013, we conducted our annual review of the various actuarial assumptions, including discount rate, expected trend in health carecosts, average remaining service period, average remaining life expectancy, per capita costs and participation level in each future year used by our independentactuary to estimate the cost and benefit obligations for our retiree health plans. Expected trends in future health care cost assumptions were adjusted from prioryear to reflect recent experience and future expectations. The initial expected trend in health care costs at this year's measurement date was 6.17% with anultimate trend rate of 4.50% expected to be reached in 2026. The initial expected trend rate at last year's measurement date was 6.30% with an ultimate trendrate of 4.50% expected to be reached in 2026. A 1.0% decrease in the health care trend rate would have decreased interest and service cost for 2013 byapproximately $14.3 million. A 1.0% increase in the health care trend rate would have increased the interest and service cost by approximately $17.3 million.The discount rate is determined each year at the measurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using aCompany-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean)uses a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's orStandard & Poor's as of the measurement date. The yield curve model parallels the plans' projected cash flows, and the underlying cash flows of the bondsincluded in the model exceed the cash flows needed to satisfy the Company plans' obligations. The OPEB plan was remeasured at December 5, 2013 to reflect93the curtailment of a portion of the plan related to the sale of five West Virginia Coal mines, the River Divison and various other locations. At December 31,2013 and December 5, 2013 (remeasurement date), the discount rate used to calculate the period end liability and the following year's expense was 4.88% and4.91%, respectively. A 0.25% increase in the discount rate would have decreased 2013 net periodic postretirement benefit costs by approximately $3.7 million.A 0.25% decrease in the discount rate would have increased 2013 net periodic postretirement benefit costs by approximately $3.8 million. Deferred gains andlosses are primarily due to historical changes in the discount rate and medical cost inflation differing from expectations in prior years. Changes to interest ratesfor the rates of returns on instruments that could be used to settle the actuarially determined plan obligations introduce substantial volatility to our costs.Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected future service of activesalary and non-represented employees to their assumed retirement age. At December 31, 2013, the average remaining service period is approximately 13 yearsfor our non-represented plans. The accumulated actuarial gains or losses related to the portion of the plan that was transferred in the sale mention above, wasrecognized in Income from Discontinued Operations.CONSOL Energy benefits are under self-insured arrangements. The self-insured benefits weighted average per capita costs used to value theDecember 31, 2013 OPEB liability was approximately 1% less than previously expected based on our trend assumption. The fully insured benefits reflect the2014 premium rates guaranteed by the respective insurance companies to value the December 31, 2013 OPEB liability. If future per capita cost or premiumrates are significantly greater or less than the projected trend rates, the per capita cost and premium rate assumptions would need to be adjusted, which couldhave a significant effect on the costs and liabilities recorded in the financial statements.The estimated liability recognized in the December 31, 2013 financial statements was $1.0 billion. For the year ended December 31, 2013, we paidapproximately $161.9 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, 2013. CONSOL Energy does not expect to contribute to the other postretirement plan in 2014. We intend to pay benefitclaims as they are due.Salaried Pensions 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.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, 2013, 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, or subsequent remeasurement date, ifapplicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. TheCompany-specific yield curve model (above-mean) uses a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds usedin the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve model parallels the plans' projected cash flows,and the underlying cash flows of the bonds included in the model exceed the cash flows needed to satisfy the Company plans'. For the years endedDecember 31, 2013 and 2012, the discount rate used to calculate the period end liability and the following year's expense was 4.87% and 4.00%, respectively.The discount rate was reset at the end of each quarter due to pension settlement accounting, see below for further discussion. A 0.25% increase in the discountrate would have decreased the 2013 net periodic pension cost by $1.8 million. A 0.25% decrease in the discount rate would have increased the 2013 netperiodic pension cost by $1.8 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differingfrom expectations. At December 31, 2013 the average remaining service period is approximately 12 years. Changes to any of these assumptions introducesubstantial volatility to our costs.The assumed rate of return on plan assets can also impact CONSOL Energy's pension liability. The rate of return on plan assets was 7.75% atDecember 31, 2013 and 8.00% at December 31, 2012. A reduction of 0.25% would have increased 2013 expense by $1.7 million. An increase of 0.25% wouldhave decreased 2013 expense by $1.7 million. The market related asset value is derived by taking the cost value of assets as of December 31, 2013 andmultiplying it by the average 36-month ratio of the market value of assets to the cost value of assets. CONSOL Energy's pension plan weighted average assetallocations at December 31, 2013 consisted of 61% equity securities and 39% debt securities.94As a result of lump sum settlements in 2013 (including those associated with the 2012 VSIP), a pension settlement charge of $39.5 million wasrecognized for both the Qualified and Non-Qualified salaried pension plans. When lump sum payments from the pension plan exceed the service and interestexpense, pension settlement accounting requires unamortized actuarial gains and loss related to the lump sum payouts be amortized immediately. At the end ofeach quarter in 2013, the pension plan was remeasured using the then current discount rate. The rates used were 4.87% at December 31, 2013, 4.80% atSeptember 30, 2013, 4.84% at June 30, 2013 and 4.12% at March 31, 2013. A settlement charge is also reasonably possible to occur in 2014 related to the saleof CCC and subsidiaries, discussed above, and related reduction in administrative staffing levels. The 2014 threshold for pension settlement recognitionis $53 million. If the threshold for pension settlement is reached, the pension settlement charge could be material to the financial results of CONSOL Energy. Also, if pension settlement is triggered in 2014, pension settlement would require the pension plan to be remeasured using updated assumptions, which wouldinclude resetting the discount rate used in the actuarial calculation. The estimated liability recognized in the December 31, 2013 financial statements was $43.8 million, which is net of the $9 million of over fundedQualified Plan assets which is included in Other Assets. Also, the estimated asset for the overfund Qualified Salaried Pension Plan of $9.0 million is includedin Other Assets in December 31, 2013 financial statements. For the year ended December 31, 2013, we contributed approximately $55.5 million to definedbenefit retirement plans other than multi-employer plans and to other pension benefits. Our obligations with respect to the Non-Qualified Plan liabilities arenon-funded at December 31, 2013. Our Qualified Plan liabilities are over funded at December 31, 2013. CONSOL Energy intends to contribute an amountthat will avoid benefit restrictions for the following plan year.Workers' Compensation and Coal Workers' Pneumoconiosis (CWP)Workers' 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, or subsequent remeasurement date, if applicable. The discount rateis determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curvemodel (above-mean) uses a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AAby Moody's or Standard & Poor's as of the measurement date. The yield curve model parallels the plans' projected cash flows, and the underlying cash flowsof the bonds included in the model exceed the cash flows needed to satisfy the Company plans' obligations. For the years ended December 31, 2013 and 2012,the discount rate used to calculate the period end liability and the following year's expense was 4.57% and 3.95%, respectively. A 0.25% increase in thediscount rate would have decreased the 2013 workers compensation expense cost by $0.4 million. A 0.25% decrease in the discount rate would have increasedthe 2013 workers compensation expense by $0.4 million. Deferred gains and losses are primarily due to historical changes in the discount rates, several yearsof favorable claims experience, various favorable state legislation changes and an overall lower incident rate than our assumptions. Accumulated actuarialgains or losses are amortized on a straight-line basis over the expected future service of active employees that are eligible to file a future workers' compensationclaim. At December 31, 2013, the average remaining service period is approximately 13 years.On December 5, 2013, the Workers’ Compensation obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries asdiscussed above. The Workers’ Compensation obligation was reduced by $105.3 million. The plan was remeasured on the date of the sale using a discountrate of 4.67% compared to December 31, 2012 discount rate of 3.95% .The estimated liability recognized in the financial statements at December 31, 2013 was approximately $85.1 million. CONSOL Energy's policy hasbeen to provide for workers' compensation benefits from operating cash flow. For the year ended December 31, 2013, we made payments for workers'compensation benefits and other related fees of approximately $28.7 million, all of which was paid from operating cash flow. Our obligations with respect tothese liabilities are unfunded at December 31, 2013. 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 assumptions95regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at themeasurement date, or subsequent remeasurement date, if applicable. The discount rate is determined using a Company-specific yield curve model (above-mean) developed with assistance of an external actuary. The Company-specific yield curve model (above-mean) uses a subset of the expanded bond universeto determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date.The yield curve model parallels the plans' projected cash flows, and the underlying cash flows of the bonds included in the model exceed the cash flowsneeded to satisfy the Company plans' obligations. For the years ended December 31, 2013 and 2012, the discount rate used to calculate the period end liabilityand the following year's expense was 4.75% and 4.03%, respectively. A 0.25% increase in the discount rate would have increased 2013 coal workers'pneumoconiosis benefit by $0.6 million. A 0.25% decrease in the discount rate would have decreased 2013 coal workers' pneumoconiosis benefit by $0.5million. Actuarial gains associated with coal workers' pneumoconiosis have resulted from numerous legislative changes over many years which have resultedin lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lowerseverity of claims filed than our assumptions originally reflected. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expectedfuture service of active employees.On December 5, 2013, the CWP obligation was reduced due to the sale of Consolidation Coal Company and its subsidiaries as discussed above. TheCWP obligation was reduced by $49.7 million. The plan was remeasured on the date of the sale using a discount rate of 4.86% compared to December 31,2012 discount rate of 4.03% .The estimated liability recognized in the financial statements at December 31, 2013 was $121.2 million. For the year ended December 31, 2013, we paidcoal workers' pneumoconiosis benefits of approximately $10.4 million, all of which was paid from operating cash flow. Our obligations with respect to theseliabilities are unfunded at December 31, 2013.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. On December 5, 2013, these obligations were reduced by $146.6 million due to the sale of Consolidation CoalCompany and its subsidiaries discussed above. 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 $601.0 million atDecember 31, 2013. 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.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 31,2013, CONSOL Energy has deferred tax liabilities in excess of deferred tax assets of approximately $31.3 million. The change from the company reporting anet deferred tax asset for 2012 to a net deferred tax liability for 2013 is mainly attributable to the assumption of certain long-term liabilities by Murray EnergyCorporation as part of the sale that closed in December 2013. In total, $414.5 million of net96deferred tax assets (including the deferred tax assets reported in Other Comprehensive Income) were removed in relation to the sale. The deferred tax assets areevaluated periodically to determine if a valuation allowance is necessary.Deferred tax valuation allowances changed significantly for the year ended December 31, 2013 compared to December 31, 2012 due to the sale toMurray Energy Corporation of certain subsidiaries with state net operating loss carry forwards of $28 million subject to a full valuation allowance. CONSOLEnergy continues to report a deferred tax asset of approximately $51.8 million relating to its state net operating loss carry forwards subject to a valuationallowance of $7.5 million. A review of positive and negative evidence regarding these benefits, primarily the history of financial and tax losses on a separatecompany basis, concluded that a partial valuation allowance was warranted. The net operating loss carry forwards expire at various times from 2018 to 2032.Management will continue to assess the realization of deferred tax assets attributable to state net operating loss carry forwards and future tax deductibledifferences based upon updated income forecast data and the feasibility of future tax planning strategies, and may record adjustments to valuation allowancesagainst these deferred tax assets in future periods that 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 isreversed 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 $29 million at December 31, 2013.Stock-Based CompensationAs of December 31, 2013, 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, 2013, $24.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over aweighted-average period of 1.67 years. See Note 19-"Stock-based Compensation" in the Notes to the Audited Consolidated Financial Statements in Item 8 inthis 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 the nature of thelawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters, and management's intended response. Future results ofoperations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. Legalfees associated with defending these various lawsuits and claims are expensed when incurred. See Note 24-Commitments and97Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for further discussion.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.Gas and Coal Reserve ValuesThere are numerous uncertainties inherent in estimating quantities and values of economically recoverable gas and coal reserves, including manyfactors beyond our control. As a result, estimates of economically recoverable gas and coal 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 gas reserves are reviewed byindependent experts each year. Our coal reserves are periodically reviewed by an independent third party consultant. Some of the factors and assumptionswhich 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 gas and coal 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.98Liquidity and Capital ResourcesCONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligationswith cash generated from operations and proceeds from borrowings. CONSOL Energy's $1.0 billion Senior Secured Credit Agreement, as amendedby Amendment No.1 dated December 5, 2013, expires April 12, 2016. The amendment on December 5, 2013 reduced the availability from$1,500,000 to $1,000,000 resulting in an acceleration of previously deferred financing charges of $3,195. The facility is secured by substantiallyall of the assets of CONSOL Energy and certain of its subsidiaries. CONSOL Energy's credit facility allows for up to $1.0 billion of borrowingsand letters of credit. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. Fees and interestrate spreads are based on a ratio of financial covenant debt to twelve-month trailing adjusted earnings before interest, taxes, depreciation, depletionand amortization (Adjusted EBITDA), measured quarterly. Financial covenant debt is comprised of the outstanding indebtedness and specific lettersof credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. The facility includes a minimum interest coverage ratio covenantof no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. The interest coverage ratio is calculated as theratio of Adjusted EBITDA to cash interest expense of CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 2.21 to 1.00at December 31, 2013. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transactionexpenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates,excluding cash distributions from CNX Gas and its subsidiaries, plus pro-rata earnings from material acquisitions. The facility also includes asenior secured leverage ratio covenant of no more than 2.00 to 1.00, measured quarterly. The senior secured leverage ratio is calculated as the ratio ofsecured debt to Adjusted EBITDA. Secured debt is defined as financial covenant debt, excluding indebtedness not secured by a lien, of CONSOLEnergy and certain of its subsidiaries. The senior secured leverage ratio was less than 1.00 to 1.00 at December 31, 2013. Covenants in the facilitylimit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends, merge with anothercompany and amend, modify or restate, in any material way, the senior unsecured notes. At December 31, 2013, the facility had no outstandingborrowings and $207 million of letters of credit outstanding, leaving $793 million of unused capacity. From time to time, CONSOL Energy isrequired to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of theseassurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit tosatisfy these requirements and these 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 or LIBOR rates plus a charge foradministrative services paid to financial institutions. At December 31, 2013, eligible accounts receivable totaled approximately $115 million. AtDecember 31, 2013, the facility had no outstanding borrowings and $66 million of letters of credit outstanding, leaving $49 million of unusedcapacity.CNX Gas' $1.0 billion Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all of the assets ofCNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1.0 billion of borrowings and letters of credit. CNX Gas can request anadditional $250 million increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facilityutilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly.The interest coverage ratio is calculated as the ratio of Adjusted EBITDA to cash interest expense for CNX Gas and its subsidiaries. The interestcoverage ratio was 25.33 to 1.00 at December 31, 2013. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00,measured quarterly. The leverage ratio is calculated as the ratio of financial covenant debt to twelve-month trailing Adjusted 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. Adjusted EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transactionexpenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cashdistributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.61 to 1.00 at December 31, 2013.Covenants in the facility limit CNX Gas' ability to dispose of assets, make investments, pay dividends and merge with another company. The creditfacility allows unlimited investments in joint ventures for the development and operation of gas gathering systems and provides for up to $600million of loans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. At December 31, 2013, thefacility had no amounts drawn and $88 million of letters of credit outstanding, leaving $912 million of unused capacity.99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 regularly 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, asset sales and our borrowing capacity will be sufficient to meet our workingcapital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments andto provide 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 $65 million at December 31, 2013. The $5 million ineffective portion of these contracts was insignificant to earnings in the yearended December 31, 2013. 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, 2013 2012 ChangeCash flows from operating activities$659 $728 $(69)Cash used in investing activities$(202) $(1,000) $798Cash used in financing activities$(151) $(82) $(69)Cash flows provided by operating activities decreased $69 million in the period-to-period comparison primarily due to the following items:•Net income increased $271 million in the period-to-period comparison;•Discontinued operations changes decreased $675 million primarily as a result of the gain on sale of CCC and certain subsidiaries toMurray Energy Corporation in December 2013;•Operating cash flows increased $214 million in the period-to-period comparison due to changes in the gain on the sale of assets. See Note3 - Acquisitions and Dispositions in the Notes to Audited Financial Statements in Item 8 of this Form 10-K for more information; and•Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods alsocontributed to the increase in operating cash flows.Net cash used in investing activities decreased $798 million in the period-to-period comparison primarily due to the following items:•Capital expenditures increased $251 million due to:•Gas segment capital expenditures increased $441 million. The increase was comprised of increased drilling costs in the Marcellus andUtica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions inMonroe and Noble Counties in Ohio, additional gas drilling rights acquired from Dominion Transmission in West Virginia and variousother individually insignificant projects;•Coal segment capital expenditures decreased $196 million. The decrease was comprised of a $27 million decrease in Bailey MineExpansion projects. Longwall shield projects decreased $71 million as well as an additional $98 million decrease in variousmiscellaneous transactions that occurred throughout both periods, none of which were individually material; and100•Other capital expenditures increased $6 million due to various miscellaneous transactions that occurred throughout both periods, none ofwhich were individually material.•Proceeds from sale of assets decreased $161 million due to various items that occurred throughout both periods. See Note 3 - Acquisitions andDispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.•Discontinued operations changes increased $1,106 million primarily as a result of the gain on the sale of CCC and certain subsidiaries to MurrayEnergy Corporation in December 2013.•Distributions from/investments in equity affiliates decreased $12 million due to various miscellaneous transactions that occurred throughout bothperiods, none of which were individually material.•Restricted cash increased $116 million due to the release of $69 million of restricted cash of which $48 million is associated with the Ram River& Scurry Canadian asset proceeds received during December 2012 and $21 million is associated with the Ryerson Dam Settlement. See Note 3 -Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.Net cash used in financing activities decreased $69 million in the period-to-period comparison primarily due to the following items:•In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy received$16 million of borrowings.•The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid inthe first quarter of 2013. Total dividends paid in the year ended December 31, 2013 were $86 million as compared to $142 million individends paid in the period ended December 31, 2012.•In 2013, CONSOL Energy repaid $38 million of borrowings under its Securitization Facility. In 2012, CONSOL Energy had proceedsof $38 million from the Securitization Facility.•The remaining change is due to various other transactions that occurred throughout both periods, none of which were individuallymaterial.The following is a summary of our significant contractual obligations at December 31, 2013 (in thousands): Payments due by Year Less Than1 Year 1-3 Years 3-5 Years More Than5 Years TotalPurchase Order Firm Commitments167,658 125,505 61,768 14,637 369,568Gas Firm Transportation73,212 134,713 137,376 568,696 913,997Long-Term Debt3,489 6,553 1,503,562 1,605,316 3,118,920Interest on Long-Term Debt245,385 490,600 310,280 240,117 1,286,382Capital (Finance) Lease Obligations8,498 15,334 13,096 19,166 56,094Interest on Capital (Finance) Lease Obligations3,557 5,493 3,790 2,110 14,950Operating Lease Obligations102,454 177,781 119,230 95,669 495,134Long-Term Liabilities—Employee Related (a)87,751 181,311 188,171 791,444 1,248,677Other Long-Term Liabilities (b)298,584 211,363 97,815 318,321 926,083Total Contractual Obligations (c)$990,588 $1,348,653 $2,435,088 $3,655,476 $8,429,805 _________________________(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 2014 contributions are expected to approximate $25 million to $35 million.(b)Other long-term liabilities include mine reclamation and closure and other long-term liability costs.(c)The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amountsand timing of these obligations.101DebtAt December 31, 2013, CONSOL Energy had total long-term debt and capital lease obligations of $3.175 billion outstanding, including the currentportion of long-term debt and capital lease obligations of $11 million. This long-term debt consisted of:•An aggregate principal amount of $1.50 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 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.Payment of the principal and interest on the notes are guaranteed by CONSOL Energy.•Advance royalty commitments of $11 million with an average interest rate of 7.93% per annum.•An aggregate principal amount of $5 million on other various rate notes maturing through June 2031.•An aggregate principal amount of $56 million of capital leases with a weighted average interest rate of 6.19% per annum.At December 31, 2013, CONSOL Energy had no outstanding borrowings and approximately $207 million of letters of credit outstanding under the $1billion senior secured revolving credit facility.At December 31, 2013, CONSOL Energy had no outstanding borrowings and had $66 million of letters of credit outstanding under the accountsreceivable securitization facility.At December 31, 2013, CNX Gas, a wholly owned subsidiary, had no outstanding borrowings and approximately $88 million of letters of creditoutstanding under the $1 billion secured revolving credit facility.Total Equity and DividendsCONSOL Energy had total equity of $5.0 billion at December 31, 2013 and $4.0 billion at December 31, 2012. Total equity increased primarily due tonet income, adjustments to actuarial liabilities and the amortization of stock-based compensation awards. These increases were offset, in part, by thedeclaration of dividends and changes in the fair value of cash flow hedges. See the Consolidated Statements of Stockholders' 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 DateFebruary 3, 2014 $0.0625 February 14, 2014 February 28, 2014November 1, 2013 $0.125 November 15, 2013 December 4, 2013July 26, 2013 $0.125 August 9, 2013 August 23, 2013April 26, 2013 $0.125 May 10, 2013 May 24, 2013On October 28, 2013, CONSOL Energy announced that in conjunction with the sale to Murray Energy, CONSOL Energy is realigning its dividendpolicy to reflect the company's increased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, for anannual rate of $0.25 per share.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 5.14 to 1.00 and our availability was approximately$793 million at December 31, 2013. The credit facility does not permit102dividend payments in the event of default. The indentures to the 2017, 2020 and 2021 notes limit dividends to $0.40 per share annually unless severalconditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaultsin the year ended December 31, 2013.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 the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally acceptedaccounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balancesheet at December 31, 2013. The various multi-employer benefit plans are discussed in Note 18—Other Employee Benefit Plans in the Notes to the AuditedConsolidated Financial Statements in Item 8 of this Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters ofcredit to secure our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the balance sheetat December 31, 2013. Management believes these items will expire without being funded. See Note 24—Commitments and Contingencies in the Notes to theAudited Consolidated Financial Statements included in Item 8 of this Form 10-K for additional details of the various financial guarantees that have beenissued by CONSOL Energy.Recent Accounting PronouncementsIn February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint andSeveral Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update isto provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the totalamount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S.generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and severalliability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following:(a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reportingentity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as wellas other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginningafter December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting fromjoint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of thisnew guidance will not have a material impact on CONSOL Energy's financial statements.103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 31,2013. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $70 million. Similarly, ahypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $72 million.CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2013, CONSOLEnergy had $3.175 billion 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, 2013. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would nothave significantly decreased net income for the period. CNX Gas also had borrowings during the period under its revolving credit facility which bears interestat a variable rate. CNX Gas’ facility had no outstanding borrowings at December 31, 2013 and bore interest at a weighted average rate of 1.66% per annumduring the year ended December 31, 2013. Due to the level of borrowings against this facility and the low weighted average interest rate in the year endedDecember 31, 2013, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income forthe 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.104Hedging VolumesAs of January 21, 2014 our hedged volumes for the periods indicated are as follows: For the Three Months Ended March 31, June 30, September 30, December 31, Total Year2014 Fixed Price Volumes Hedged Bcf31.9 32.2 32.6 32.6 129.3Weighted Average Hedge Price/Mcf$4.61 $4.61 $4.61 $4.61 $4.612015 Fixed Price Volumes Hedged Bcf19.4 19.6 19.8 19.8 78.6Weighted Average Hedge Price/Mcf$4.10 $4.10 $4.10 $4.10 $4.102016 Fixed Price Volumes Hedged Bcf17.7 17.8 17.9 17.9 71.3Weighted Average Hedge Price/Mcf$4.20 $4.20 $4.20 $4.20 $4.20105ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAINDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageReport of Independent Registered Public Accounting Firm107Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011108Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011109Consolidated Balance Sheets at December 31, 2013 and 2012110Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2013, 2012 and 2011112Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011113Notes to the Audited Consolidated Financial Statements114106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, 2013 and 2012, and therelated consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period endedDecember 31, 2013. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are theresponsibility of the Company's management. 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, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in theperiod ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 7, 2014 expressed anunqualified opinion thereon./s/ Ernst & Young LLPPittsburgh, PennsylvaniaFebruary 7, 2014107CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME(Dollars in thousands, except per share data) For the Years Ended December 31, 2013 2012 2011Sales—Outside$3,015,551 $3,122,550 $3,991,007Sales—Gas Royalty Interests63,202 49,405 66,929Sales—Purchased Gas6,531 3,316 4,344Freight—Outside35,438 107,079 175,633Other Income (Note 4)178,963 395,176 139,132Total Revenue and Other Income3,299,685 3,677,526 4,377,045Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion andamortization shown below)2,228,952 2,221,859 2,266,560Gas Royalty Interests Costs53,028 38,867 59,331Purchased Gas Costs4,837 2,711 3,831Freight Expense35,438 107,079 175,444Selling, General and Administrative Expenses90,408 90,740 114,643Depreciation, Depletion and Amortization461,122 427,115 430,577Interest Expense (Note 5)219,198 220,042 248,344Taxes Other Than Income (Note 6)160,627 162,426 174,392Loss on Debt Extinguishment (Note 14)— — 16,090Transaction and Financing Fees (Note 14)— — 14,907Total Costs3,253,610 3,270,839 3,504,119Earnings Before Income Taxes46,075 406,687 872,926Income Taxes (Note 7)(33,189) 88,728 191,251Income from Continuing Operations79,264 317,959 681,675Income (Loss) from Discontinued Operations, net of tax (Note 2)579,792 70,114 (49,178)Net Income659,056 388,073 632,497Less: Net Loss Attributable to Noncontrolling Interest1,386 397 —Net Income Attributable to CONSOL Energy Inc. Shareholders$660,442 $388,470 $632,497Earnings Per Share (Note 1): Basic: Income from Continuing Operations$0.35 $1.40 $3.01Income (Loss) from Discontinued Operations2.54 0.31 (0.22)Net Income$2.89 $1.71 $2.79Dilutive: Income from Continuing Operations$0.35 $1.39 $2.98Income (Loss) from Discontinued Operations2.52 0.31 (0.22)Net Income$2.87 $1.70 $2.76Weighted Average Number of Common Shares Outstanding (Note 1): Basic228,728,628 227,593,524 226,680,369Dilutive230,077,942 229,141,767 229,003,599Dividends Paid Per Share$0.375 $0.625 $0.425The accompanying notes are an integral part of these financial statements.108CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(Dollars in thousands) For the Years Ended December 31, 2013 2012 2011Net Income$659,056 $388,073 $632,497Other Comprehensive Income: Treasury Rate Lock (Net of tax: $-, $-, $59)— — (96)Actuarially Determined Long-Term LiabilityAdjustments (Net of tax: ($276,928), ($77,871),$20,259)456,493 129,231 (32,813)Net Increase in the Value of Cash Flow Hedge (Net oftax: ($29,407), ($73,593), ($129,235))45,631 114,240 200,700Reclassification of Cash Flow Hedges from OtherComprehensive Income to Earnings (Net of tax:$53,990, $121,484, $60,925)(79,899) (189,259) (95,007) Other Comprehensive Income422,225 54,212 72,784 Comprehensive Income1,081,281 442,285 705,281 Less: Comprehensive Loss Attributable toNoncontrolling Interest1,386 397 — Comprehensive Income Attributable to CONSOLEnergy Inc. Shareholders$1,082,667 $442,682 $705,281The accompanying notes are an integral part of these financial statements.109CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(Dollars in thousands) December 31, 2013 December 31, 2012ASSETS Current Assets: Cash and Cash Equivalents$327,420 $21,862Accounts and Notes Receivable: Trade332,574 428,328Notes Receivable25,861 318,387Other Receivables243,973 131,131Accounts Receivable—Securitized (Note 10)— 37,846Inventories (Note 9)157,914 170,808Deferred Income Taxes (Note 7)211,303 84,777Recoverable Income Taxes10,705 —Restricted Cash (Note 1)— 48,294Prepaid Expenses135,842 148,431Current Assets of Discontinued Operations (Note 2)— 149,230Total Current Assets1,445,592 1,539,094Property, Plant and Equipment (Note 11): Property, Plant and Equipment13,578,509 12,121,557Less—Accumulated Depreciation, Depletion and Amortization4,136,247 3,613,499Property, Plant and Equipment of Discontinued Operations, Net (Note 2)— 1,682,909Total Property, Plant and Equipment—Net9,442,262 10,190,967Other Assets: Restricted Cash (Note 1)— 20,379Investment in Affiliates291,675 222,830Notes Receivable125 25,977Other214,013 216,235Other Assets of Discontinued Operations (Note 2)— 782,112Total Other Assets505,813 1,267,533 TOTAL ASSETS$11,393,667 $12,997,594The accompanying notes are an integral part of these financial statements.110CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(Dollars in thousands, except per share data) December 31, 2013 December 31, 2012LIABILITIES AND EQUITY Current Liabilities: Accounts Payable$514,580 $498,515Current Portion of Long-Term Debt (Note 14 and Note 15)11,455 12,484Short-Term Notes Payable (Note 12)— 25,073Accrued Income Taxes— 34,219Borrowings Under Securitization Facility (Note 10)— 37,846Other Accrued Liabilities (Note 13)565,697 545,748Current Liabilities of Discontinued Operations (Note 2)28,239 233,214Total Current Liabilities1,119,971 1,387,099Long-Term Debt: Long-Term Debt (Note 14)3,115,963 3,123,600Capital Lease Obligations (Note 15)47,596 49,413Long-Term Debt of Discontinued Operations (Note 2)— 1,573Total Long-Term Debt3,163,559 3,174,586Deferred Credits and Other Liabilities: Deferred Income Taxes (Note 7)242,643 326,685Postretirement Benefits Other Than Pensions (Note 16)961,127 882,600Pneumoconiosis Benefits (Note 17)111,971 114,136Mine Closing (Note 8)320,723 289,818Gas Well Closing (Note 8)175,603 146,002Workers’ Compensation (Note 17)71,468 60,396Salary Retirement (Note 16)48,252 218,004Reclamation (Note 8)40,706 47,965Other131,355 118,307Deferred Credits and Other Liabilities of Discontinued Operations (Note 2)— 2,278,251Total Deferred Credits and Other Liabilities2,103,848 4,482,164TOTAL LIABILITIES6,387,378 9,043,849Stockholders’ Equity: Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,145,736 Issued and Outstanding atDecember 31, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 20122,294 2,284Capital in Excess of Par Value2,364,592 2,296,908Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding— —Retained Earnings2,964,520 2,402,551Accumulated Other Comprehensive Loss - Continuing Operations(325,117) (747,342)Common Stock in Treasury, at Cost—No Shares at December 31, 2013 and 34,755 Shares at December 31,2012— (609)Total CONSOL Energy Inc. Stockholders’ Equity5,006,289 3,953,792Noncontrolling Interest— (47)TOTAL EQUITY5,006,2893,953,745 TOTAL LIABILITIES AND EQUITY$11,393,667 $12,997,594The accompanying notes are an integral part of these financial statements.111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, 2010$2,273 $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 $20,259 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, 20112,273 2,234,775 2,184,737 (801,554) (9,346) 3,610,885 — 3,610,885Net Income— — 388,470 — — 388,470 (397) 388,073Gas Cash Flow Hedge (Net of $47,891 Tax)— — — (75,019) — (75,019) — (75,019)Actuarially Determined Long-Term LiabilityAdjustments (Net of ($77,871) Tax)— — — 129,231 — 129,231 — 129,231Comprehensive Income (Loss)— — 388,470 54,212 — 442,682 (397) 442,285Issuance of Treasury Stock— — (28,378) — 8,737 (19,641) — (19,641)Issuance of Common Stock11 8,267 — — — 8,278 — 8,278Tax Benefit from Stock-Based Compensation— 6,028 — — — 6,028 — 6,028Amortization of Stock-Based Compensation Awards— 47,838 — — — 47,838 — 47,838Net Change in Noncontrolling Interest— — — — — — 350 350Dividends ($0.625 per share)— — (142,278) — — (142,278) — (142,278)Balance at December 31, 20122,284 2,296,908 2,402,551 (747,342) (609) 3,953,792 (47) 3,953,745Net Income— — 660,442 — — 660,442 (1,386) 659,056Gas Cash Flow Hedge (Net of $24,583 Tax)— — — (34,268) — (34,268) — (34,268)Actuarially Determined Long-Term LiabilityAdjustments (Net of ($276,928) Tax)— — — 456,493 — 456,493 — 456,493Comprehensive Income (Loss)— — 660,442 422,225 — 1,082,667 (1,386) 1,081,281Issuance of Treasury Stock— — (12,641) — 609 (12,032) — (12,032)Issuance of Common Stock10 3,717 — — — 3,727 — 3,727Tax Cost from Stock-Based Compensation— (2,075) — — — (2,075) — (2,075)Amortization of Stock-Based Compensation Awards— 66,042 — — — 66,042 — 66,042Net Change in Noncontrolling Interest— — — — — — 1,433 1,433Dividends ($0.375 per share)— — (85,832) — — (85,832) — (85,832)Balance at December 31, 2013$2,294 $2,364,592 $2,964,520 $(325,117) $— $5,006,289 $— $5,006,289The accompanying notes are an integral part of these financial statements.112CONSOL ENERGY INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(Dollars in thousands)For the Years Ended December 31, 2013 2012 2011Cash Flows from Operating Activities: Net Income$659,056 $388,073 $632,497Adjustments to Reconcile Net Income to Net Cash Provided By Continuing Operating Activities: Net (Loss) Income from Discontinued Operations(579,792) (70,114) 49,178Depreciation, Depletion and Amortization461,122 427,115 430,577Stock-Based Compensation56,987 41,127 42,131Gain on Sale of Assets(67,480) (282,006) (45,673)Loss on Debt Extinguishment— — 16,090Deferred Income Taxes(36,777) 10,899 (2,373)Equity in Earnings of Affiliates(33,133) (27,048) (24,663)Changes in Operating Assets: Accounts and Notes Receivable135,970 (20,218) (83,770)Inventories12,894 21,166 5,509Prepaid Expenses(3,219) 12,435 3,047Changes in Other Assets31,146 (7,041) 23,534Changes in Operating Liabilities: Accounts Payable(99,944) (23,918) 142,843Other Operating Liabilities(31,701) (50,790) 78,530Changes in Other Liabilities5,844 12,876 38,413Other42,597 24,786 23,001Net Cash Provided by Continuing Operations553,570 457,342 1,328,871Net Cash Provided by Discontinued Operating Activities105,206 270,771 198,735Net Cash Provided by Operating Activities658,776 728,113 1,527,606Cash Flows from Investing Activities: Capital Expenditures(1,496,056) (1,245,497) (1,178,375)Change in Restricted Cash68,673 (48,294) —Proceeds from Sales of Assets483,969 645,621 747,285(Investments in) Distributions from Equity Affiliates(35,712) (23,451) 55,876Net Cash Used in Continuing Operations(979,126) (671,621) (375,214)Net Cash Provided by (Used In) Discontinued Investing Activities777,145 (328,789) (203,310)Net Cash Used in Investing Activities(201,981) (1,000,410) (578,524)Cash Flows from Financing Activities: Payments on Short-Term Borrowings— — (284,000)(Payments on) Proceeds from Miscellaneous Borrowings(31,544) 16,195 (11,080)(Payments on) Proceeds from Securitization Facility(37,846) 37,846 (200,000)Payments on Long-Term Notes, Including Redemption Premium— — (265,785)Proceeds from Issuance of Long-Term Notes— — 250,000Tax Benefit from Stock-Based Compensation2,929 8,678 8,281Dividends Paid(85,832) (142,278) (96,356)Proceeds from Issuance of Common Stock3,727 8,278 —(Purchases) Issuance of Treasury Stock(2,151) (9,485) 9,033Debt Issuance and Financing Fees— (210) (15,686)Net Cash Used in Continuing Operations(150,717) (80,976) (605,593)Net Cash Used in Discontinued Financing Activities(520) (601) (547)Net Cash Used in Financing Activities(151,237) (81,577) (606,140)Net Increase (Decrease) in Cash and Cash Equivalents305,558 (353,874) 342,942Cash and Cash Equivalents at Beginning of Period21,862 375,736 32,794Cash and Cash Equivalents at End of Period$327,420 $21,862 $375,736The accompanying notes are an integral part of these financial statements.113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.Discontinued OperationsBusinesses to be divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale. For businessesclassified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets andliabilities of discontinued operations on the Consolidated Balance Sheet and to discontinued operations on the Consolidated Statements of Income and CashFlows, respectively, for all periods presented. The gains or losses associated with these divested businesses are recorded in discontinued operations theConsolidated Statements of Income. Additionally, the accompanying notes, including segment information do not include the assets, liabilities, or operatingresults of businesses classified as discontinued operations for all periods presented. Management does not expect any significant continuing involvement withthese businesses following their divestiture, and these businesses are expected to be disposed of within one year.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 reserves value.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, depreciation, depletion, amortization, and other related costs. The cost of merchandise forresale is determined by the last-in, first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. Thecost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our coal and gasoperations.114Property, Plant and Equipment:CONSOL Energy uses the successful efforts method of accounting for gas producing activities. Costs of property acquisitions, successful exploratory,development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unprovedmineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if thedetermination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing propertiesand mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, or at a minimumonce a year; those revisions are accounted for prospectively as changes in accounting estimates.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.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.Coal 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.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.Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:115 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.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 years ended December 31,2013, 2012, and 2011.Capitalized costs of unproved gas properties are evaluated for recoverability on a prospect basis. Indicators of potential impairment include potentialshifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proved reserves, the relatedcosts are expensed in the period the determination is made. Exploration expense was $61,119, $39,029 and $18,095 for the years ended December 31, 2013,2012 and 2011, respectively, which was primarily related to lease expirations.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:For the year ended December 31, 2012, restricted cash included a $48,294 deposit into escrow associated with the Ram River Asset sale. The depositwas released upon CONSOL Energy's filing of all Canadian tax returns associated with the transaction. For the year ended December 31, 2012, restricted cashalso included a $20,379 deposit into escrow as security to perfect CONSOL Energy's appeal to the Pennsylvania Environmental Hearing Board under theapplicable statute related to the Ryerson dam litigation . Both escrow accounts were released in the year ended December 31, 2013 and are reflected in theChange in Restricted Cash line included in Net Cash Used in Investing Activities of the Consolidated Statement of Cash Flows.116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. Differences between actual and expected results or changes in the value of obligations are recognized through Other ComprehensiveIncome.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 topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate offair 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 asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation isrecognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Cost of GoodsSold and Other Operating Charges on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gaswells, which includes treatment of water and the reclamation of land upon exhaustion of gas and coal 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 salaried employees. These plans are accounted forusing the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The cost of these retiree benefitsare recognized over the employees' service period. CONSOL Energy uses actuarial methods and assumptions in the valuation of defined benefit obligationsand the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized throughOther Comprehensive Income.Revenue Recognition:Revenues are recognized when title passes to the customers. For gas sales, this occurs at the contractual point of delivery. For domestic coal sales, thisgenerally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels atterminal locations. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, land and research anddevelopment, 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.117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 gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. Royalty expenses forcoal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. These royalty expenses arepaid in cash in accordance with the terms of each agreement. Revenues for gas and coal sold related to production under royalty contracts, versus owned byCONSOL Energy, are recorded on a gross basis.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 of thesematters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and managementsintended response. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending thesevarious lawsuits and claims are expensed when incurred.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 the 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 19–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: 118 For the Years Ended December 31, 2013 2012 2011Anti-Dilutive Options1,976,549 2,411,963 1,156,018Anti-Dilutive Restricted Stock Units282,230 8,822 —Anti-Dilutive Performance Share Units— 445,847 —Anti-Dilutive Performance Share Options802,804 501,744 — 3,061,583 3,368,376 1,156,018The computations for basic and dilutive earnings per share are as follows: For the Years Ended December 31, 2013 2012 2011Income from Continuing Operations79,264 317,959 681,675Income (Loss) from Discontinuing Operations579,792 70,114 (49,178)Less: Net Loss Attributable to Noncontrolling Interest1,386 397 —Net income attributable to CONSOL Energy Inc. shareholders$660,442 $388,470 $632,497Weighted average shares of common stock outstanding: Basic228,728,628 227,593,524 226,680,369Effect of stock-based compensation awards1,349,314 1,548,243 2,323,230Dilutive230,077,942 229,141,767 229,003,599Earnings per share: Basic (Continuing Operations)$0.35 $1.40 $3.01Basic (Discontinuing Operations)2.54 0.31 (0.22)Total Basic$2.89 $1.71 $2.79 Dilutive (Continuing Operations)$0.35 $1.39 $2.98Dilutive (Discontinuing Operations)2.52 0.31 (0.22)Total Dilutive$2.87 $1.70 $2.76Shares of common stock outstanding were as follows: 2013 2012 2011Balance, beginning of year 228,094,712 227,056,212 226,162,133Issuance related to Stock-Based Compensation(1) 1,051,024 1,038,500 894,079Balance, end of year 229,145,736 228,094,712 227,056,212(1) See Note 19–Stock-Based Compensation for additional information.119Other Comprehensive Income (Loss):Changes in Accumulated Other Comprehensive Income / (Loss) by component, net of tax, were as follows: Gains and Losses onCash Flow Hedges PostretirementBenefits TotalBalance at December 31, 2012$76,761 $(824,103) $(747,342)Other comprehensive income before reclassifications45,631 140,250 185,881 Amounts reclassified from accumulated othercomprehensive income(79,899) 316,243 236,344 Other comprehensive income(34,268) 456,493 422,225 Balance at December 31, 2013$42,493 $(367,610) $(325,117)The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss: For the Years Ended December 31, 2013 2012 2011Derivative Instruments (Note 23) Natural gas price swaps$(133,889) $(310,743) $(155,932)Tax benefit53,990 121,484 60,925 Net of tax$(79,899) $(189,259) $(95,007)Actuarially Determined Long-Term Liability Adjustments*(Note 16 and Note 17) Amortization of prior service costs$(32,164) $(53,853) $(47,792)Recognized net actuarial loss86,481 106,299 119,262 Settlement loss39,482 — — Total93,799 52,446 71,470 Tax expense(35,806) (19,720) (27,416)Net of tax$57,993 $32,726 $44,054 *Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended December 31, 2013, December 31,2012 and December 31, 2011. Excludes $258,250, net of tax, of reclassifications of adjustments out of accumulated other comprehensive income related todiscontinued operations for the year ended December 31, 2013.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 of120assets acquired and liabilities assumed requires management's judgment and often involves the use of significant estimates and assumptions with respect tofuture cash inflows and outflows, discount rates and asset lives, among other items.Recent Accounting Pronouncements:In February 2013, the Financial Accounting Standards Board issued Update 2013-04 - Liabilities (Topic 405): Obligations Resulting from Joint andSeveral Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The objective of the amendments in this update isto provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the totalamount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S.generally accepted accounting principles (GAAP). The guidance in this update requires an entity to measure obligations resulting from joint and severalliability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following:(a.) The amount the reporting entity agreed to pay on the basis of its arrangement amount with its co-obligors, and (b.) Any additional amount the reportingentity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as wellas other information about those obligations. The amendments in this update are effective for fiscal years, and interim periods within those years, beginningafter December 15, 2013. The amendments in this update should be applied retrospectively to all prior periods presented for those obligations resulting fromjoint and several liability arrangements within the update's scope that exist at the beginning of an entity's fiscal year of adoption. We believe adoption of thisnew guidance will not have a material impact on CONSOL Energy's financial statements.Reclassifications: Certain amounts in prior periods have been reclassified to conform with the report classifications of the years ended December 31, 2013, 2012 and2011, respectively, with no effect on previously reported net income or stockholders' equity.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—DISCONTINUED OPERATIONS:In December 2013, CONSOL Energy completed the sale of its Consolidation Coal Company (CCC) subsidiary, which includes all five of its longwallcoal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). CONSOL Energy retained overriding royalty interests in certainreserves sold in the agreement. Murray Energy also assumed $2,050,656 of CONSOL Energy's employee benefit obligations valued as of December 5, 2013and its UMWA 1974 Pension Trust obligations. Murray Energy is primarily liable for all 1993 Coal Act liabilities. Cash proceeds of $825,285 werereceived related to this transaction, which were net of $24,715 in transaction fees. Proceeds are subject to adjustments related to working capital. A pre-taxgain of $1,035,346 was included in Income from Discontinued Operations on the Consolidated Statement of Income.For all periods presented in the accompanying Consolidated Statement of Income, the sale of CCC was classified as discontinued operations. Therewere no other active businesses classified as discontinued operations in the three-year period ended December 31, 2013.In late 2013, CONSOL Energy reclassified CCC to discontinued operations based on the decision to divest the business. The Consolidated FinancialStatements for all periods presented were reclassified to reflect the business in discontinued operations. The divestiture of the CCC was completed onDecember 5, 2013.The following table details selected financial information for the divested business included within discontinued operations: 121 For the Years Ended December 31, 2013 2012 2011Sales $2,598,875 $1,717,926 $1,740,196Income (Loss) from operations before income taxes $969,685 $90,587 $(84,972)Income taxes (expense) benefit (389,893) (20,473) 35,794Income (loss) from discontinued operations $579,792 $70,114 $(49,178)The major classes of assets and liabilities of discontinued operations are as follows: December 31,2013 December 31, 2012Assets: Inventory $— $76,958Current Deferred Income Tax Asset — 63,327Other Current Assets — 8,945Properties, plants, and equipment — 1,682,909Deferred Income Tax Asset — 771,270Other assets — 10,842Assets of discontinued operations $— $2,614,251Liabilities: Current Liabilities $28,239 $233,214Long Term Debt — 1,573Postretirement Benefits Other Than Pensions — 1,949,801Pneumoconiosis Benefits — 60,645Workers' Compensation — 95,252Mine Closing — 156,909Other liabilities — 15,644Liabilities of discontinued operations $28,239 $2,513,038NOTE 3—ACQUISITIONS AND DISPOSITIONS:In December 2013, CONSOL Energy acquired the gas drilling rights to approximately 90,000 contiguous acres from Dominion Transmission, a unitof Dominion Resources. The acreage, which is associated with Dominion’s Fink-Kennedy, Lost Creek, and Racket Newberne gas storage fields in WestVirginia, lies in the northern portion of Lewis County and the southern portion of Harrison County. CONSOL anticipates that over one-half of the acres willhave wet gas. CONSOL Energy has acquired the gas rights to both the Marcellus Shale and the Upper Devonian formations in the storage fields.Consideration of up to $190 million will be paid by CONSOL Energy in two installments: 50% was paid at closing and the balance is due over time as theacres are drilled. In addition, CONSOL Energy will pay an overriding royalty to Dominion Resources based on a sliding scale. Finally, CONSOL Energyhas committed to be an anchor shipper on Dominion’s transmission system, with the specific terms to be negotiated at a future date. Noble Energy, our jointventure partner, acquired 50% of the acres and accordingly will reimburse CONSOL Energy for 50% of the associated costs. CONSOL Energy paid$91,243 in 2013 related to this transaction. In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada.The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for thesale were $24,764. A gain of $15,260 was included in Other Income in the Consolidated Statement of Income.In June 2013, CONSOL Energy completed the sale of Potomac coal reserves in Grant and Tucker Counties in West Virginia. Cash proceeds for thesale were $25,000. A gain of $24,663 was included in Other Income in the Consolidated Statement of Income. 122In April 2013, the Company and the Commonwealth of Pennsylvania (Commonwealth) entered into a Settlement Agreement and Release settling all ofthe Commonwealth's claims regarding the Ryerson Park Dam (Dam) and the Ryerson Park Lake (Lake). The Settlement provided, in part, for the payment tothe Commonwealth of $36,000 for use to rebuild the Dam and restore the Lake with $13,728 of the settlement amount credited to lease bonus and royaltypayments on the Commonwealth's Marcellus gas interests within the Park, subject to the Company's agreement to extract the gas from surface facilities locatedoutside of the boundaries of the Park. The Settlement also provided, in part, for the conveyance by the Company to the Commonwealth of eight surfaceparcels containing approximately 506 acres of land adjoining the Park after the parcels are no longer needed for the Company's operations and the conveyanceby the Commonwealth to the Company of certain coal and mining rights in an area of the Bailey Mine where a mining permit application is currently pending.In March 2013, CNX Gas Company LLC (CNX Gas Company), a wholly owned subsidiary of CONSOL Energy, completed negotiations with theAllegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the lease of the oil and gasrights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play. CNX Gas Companypaid $46,315 as an up-front bonus payment at closing. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for aportion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. CNX Gas Company must spud a wellby February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and CNX Gas Company forgoes the bonus. Our joint venturepartner, Noble Energy Inc., has acquired a 50% interest in the acreage and accordingly, reimbursed CNX Gas Company for 50% of the associated costsduring the year ended December 31, 2013.In January 2013, CONSOL Energy completed a sale-leaseback of longwall shields for the Bailey Mine. Cash proceeds for the sale were $71,166. Aloss of $358 was recognized due to transaction fees and was included in Other Income in the Consolidated Statement of Income. The lease has been accountedfor as an operating lease. The lease term is five years.On December 21, 2012, CONSOL Energy completed the disposition of its non-producing Ram River & Scurry Ram assets in Western Canadawhich consisted of 36 thousand acres of coal lands. In December 2012, cash proceeds of $51,869 were received related to this transaction. These proceedswere net of $637 in transaction fees. Additionally, a note receivable was recognized in 2012 related to the two additional cash payments to be received in June2013 and June 2014. Payment of $25,500 was received in June 2013. A note receivable of $24,500 was included in Accounts and Notes Receivables - NotesReceivables in the Consolidated Balance Sheet at December 31, 2013. The gain on the transaction was $89,943 and was included in Other Income in theConsolidated Statement of Income for the year ended December 31, 2012.On June 29, 2012, CONSOL Energy completed the disposition of its non-producing Northern Powder River Basin assets in southern Montana andnorthern Wyoming for cash proceeds of $169,500. The assets consisted of CONSOL Energy's 50% interest in Youngs Creek Mining Company LLC,CONSOL Energy's 50% interest in CX Ranch and related properties in and around Sheridan, Wyoming. The gain on the transaction was $150,677 and isincluded in Other Income in the Consolidated Statement of Income for the year ended December 31, 2012. Additionally, CONSOL Energy retained an 8%production royalty interest on approximately 200 million tons of permitted fee coal.On April 4, 2012, CONSOL Energy completed the disposition of its non-producing Elk Creek property in southern West Virginia, which consisted of20 thousand acres of coal lands and surface rights, for proceeds of $26,000. The gain on the transaction was $11,235 and is included in Other Income in theConsolidated Statement of Income for the year ended December 31, 2012.On February 9, 2012, CONSOL Energy completed the disposition of its Burning Star No. 4 property in Illinois, which consisted of 4.3 thousand acresof coal lands and surface rights, for proceeds of $13,023. The gain on the transaction was $11,261 and is included in Other Income in the ConsolidatedStatement of Income for the year ended December 31, 2012.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 were recorded ascash 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 for the yearended December 31, 2011.123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 proceeds of $193,000 before transaction fees of $2,619. The net gainon the transaction was $41,057 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011.NOTE 4—OTHER INCOME: For the Years Ended December 31, 2013 2012 2011Gain on disposition of assets (a) $67,480 $282,006 $45,673Equity in earnings of affiliates 33,133 27,048 24,663Royalty income 16,906 16,853 17,969Interest income 15,889 28,937 8,919Pennsylvania Turnpike Settlement 9,000 — —Right-of-way issuance 4,536 3,966 12,157Other 32,019 36,366 29,751 Total Other Income $178,963 $395,176 $139,132(a) See Note 3 - Acquisitions and Dispositions for additional information.NOTE 5—INTEREST EXPENSE: For the Years Ended December 31, 2013 2012 2011Interest on debt $260,233 $256,800 $264,080Interest on other payables 2,682 1,296 (189)Interest capitalized (43,717) (38,054) (15,547) Total Interest Expense $219,198 $220,042 $248,344Interest on other payables for the year ended December 31, 2013 includes interest expense of $1,369 related to uncertain tax positions. Interest on otherpayables for the years ended December 31, 2012 and December 31, 2011 includes a reversal of interest expense of $543 and $3,096, respectively, related touncertain tax positions. See Note 7–Income Taxes, for further discussion.NOTE 6—TAXES OTHER THAN INCOME: For the Years Ended December 31, 2013 2012 2011Production taxes $84,984 $77,629 $99,442Property taxes 36,338 43,679 35,495Payroll taxes 32,779 32,478 33,155Capital stock & franchise tax 6,833 9,013 3,670Virginia employment enhancement tax credit (4,683) (4,311) (6,109)Other 4,376 3,938 8,739 Total Taxes Other Than Income $160,627 $162,426 $174,392124NOTE 7—INCOME TAXES:Income tax (benefit) expense provided on earnings from continuing operations consisted of: For The Years Ended December 31, 2013 2012 2011Current: U.S. Federal$6,728 $44,727 $161,474U.S. State(10,903) 1,508 32,150Non-U.S7,763 31,594 — 3,588 77,829 193,624Deferred: U.S. Federal(32,125) 23,300 30,034U.S. State(4,652) (14,166) (32,407)Non-U.S.— 1,765 — (36,777) 10,899 (2,373) Total Income (Benefit) Expense$(33,189) $88,728 $191,251The components of the net deferred tax liabilities are as follows: December 31, 2013 2012Deferred Tax Assets: Postretirement benefits other than pensions$337,836 $347,584Mine closing37,306 57,370Alternative minimum tax159,933 54,609Pneumoconiosis benefits44,580 46,164Workers' compensation31,008 25,191Salary retirement14,330 83,077Net operating loss168,658 27,277Mine subsidence35,655 20,804Reclamation20,978 26,716Capital lease22,489 23,103Other160,567 149,435Total Deferred Tax Assets1,033,340 861,330Valuation Allowance**(7,532) (4,500)Net Deferred Tax Assets1,025,808 856,830 Deferred Tax Liabilities: Property, plant and equipment(954,007) (976,505)Gas hedge(27,741) (51,006)Advance mining royalties(38,105) (33,950)Other(37,295) (37,277)Total Deferred Tax Liabilities(1,057,148) (1,098,738) Net Deferred Tax Liability$(31,340) $(241,908)**Valuation allowance of $(7,532) has been allocated to long-term deferred tax asset for 2013. Valuation allowance of $(4,500) has been allocated tolong-term deferred tax asset for 2012.125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, 2013 and 2012, 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 in prior periods and the inability to achieve forecasted results for thoseperiods. CONSOL Energy continues to report, on an after federal tax basis, a deferred tax asset related to federal operating losses of $116,893 and stateoperating losses of $51,765 with a related valuation allowance of $7,532 at December 31, 2013. The deferred tax asset related to state operating losses, on anafter tax adjusted basis, was $27,277 with a related valuation allowance of $4,500 at December 31, 2012. A review of positive and negative evidenceregarding these tax benefits concluded that the valuation allowances for various CONSOL Energy subsidiaries was warranted. The net operating losses expireat various times between 2018 and 2032.The deferred tax assets attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial andtax losses were also reviewed for positive and negative evidence regarding the realization of the deferred tax assets. A valuation allowance of $4, after federal taxadjusted basis, has also been recorded for 2013. No valuation allowance was recognized in 2012. No allowances were recognized through other comprehensiveincome in 2013 or 2012. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibilityof future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that couldmaterially impact net income. The following is a reconciliation stated as a percentage of pretax income from continuing operations, of the United States statutory federal income tax rateto CONSOL Energy's effective tax rate: For the Years Ended December 31, 2013 2012 2011 Amount Percent Amount Percent Amount PercentStatutory U.S. federal income tax rate$16,126 35.0 % $142,340 35.0 % $305,524 35.0 %Excess tax depletion(51,104) (110.9) (49,572) (12.2) (72,577) (8.3)Effect of medicare prescription drug, improvementand modernization act of 20032,112 4.6 2,112 0.5 2,112 0.2Effect of domestic production activities5,680 12.3 (7,215) (1.8) (21,938) (2.5)Federal and state tax accrual to tax returnreconciliation(1,406) (3.1) 6,004 1.5 2,257 0.3IRS and state tax examination settlements3 — (925) (0.2) (5,188) (0.6)Net effect of state income taxes(2,399) (5.2) (8,737) (2.1) 2,926 0.3Effect of releasing valuation allowance(4,659) (10.1) — — (22,618) (2.6)Effect of foreign tax— — 1,765 0.4 (1,822) (0.2)Other2,458 5.3 2,956 0.7 2,575 0.3Income Tax Expense / Effective Rate$(33,189) (72.1)% $88,728 21.8 % $191,251 21.9 %126A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows: For the Years Ended December 31, 2013 2012Balance at beginning of period$34,786 $37,586Increase in unrecognized tax benefits resulting from tax positions taken during current period— —Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior periods— —Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations— (2,800)Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities— —Balance at end of period$34,786 $34,786If these unrecognized tax benefits were recognized, CONSOL Energy's effective tax rate would be impacted by $2,071 at December 31, 2013 and 2012.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.In 2013, CONSOL Energy recognized no changes in unrecognized tax benefits. The IRS is continuing its audit of tax years 2008 and 2009 in 2014.During the next year, the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions.The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy's net income for the twelve-month period.CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2013 and 2012, the Companyhad an accrued liability of $6,200 and $4,831 respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $1,369 ,$(543) and $(3,096) that were recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011,respectively. During the year ended December 31, 2013, CONSOL Energy paid no interest related to income tax deficiencies.CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2013, 2012 and 2011,there were no accrued penalties recognized.NOTE 8—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, 2013 and 2012 is as follows: As of December 31, 2013 2012Balance at beginning of period $539,177 $500,648Accretion expense 41,909 37,922Payments (38,198) (36,086)Revisions in estimated cash flows 42,558 40,832Other 15,429 (4,139)Balance at end of period $600,875 $539,177For the year ended December 31, 2013, Other includes $15,429 related to a contractual agreement between CONSOL Energy and Murray Energywhereas CONSOL Energy will retain the obligation of water treatment at sixteen locations sold to Murray Energy.127For the year ended December 31, 2012, Other includes $(4,139) related to the disposition of the non-producing Elk Creek property. See Note 3 -Acquisitions and Dispositions for additional details.NOTE 9—INVENTORIES:Inventory components consist of the following: December 31, 2013 2012Coal$31,944 $53,452Merchandise for resale38,263 35,363Supplies87,707 81,993Total Inventories$157,914 $170,808Inventories 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, depreciation, depletion and amortization, and other related costs.Merchandise 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 $18,836 and $19,700 at December 31, 2013 and December 31, 2012, respectively.NOTE 10—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, 2013, there were letters of credit outstanding against the facility of$66,055. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have amaterial adverse effect on the Company's financial condition. No amounts related to these financial guarantees and letters of credit are recorded as liabilities onthe financial statements.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, our collection experiencehistory and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximatesthe total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutionsfor a fee based upon market rates for similar services.In accordance with the Transfers and Servicing Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification,CONSOL Energy records transactions under the securitization facility as secured borrowings on the Consolidated Balance Sheets. The pledge of collateral isreported as Accounts Receivable - Securitized and the borrowings are classified as debt in Borrowings under Securitization Facility.The cost of funds under this facility is based upon LIBOR and commercial paper rates, plus a charge for administrative services paid to the financialinstitutions. Costs associated with the receivables facility totaled $1,737, $1,723 and $1,986 for the years ended December 31, 2013, 2012 and 2011,respectively. These costs have been recorded as financing fees which are included in Cost of Goods Sold and Other Operating Charges in the ConsolidatedStatements of Income. No servicing asset or liability has been recorded. The receivables facility expires in March 2017 with the underlying liquidity agreementrenewing annually each March.At December 31, 2013 and December 31, 2012, eligible accounts receivable totaled $115,000 and $200,000, respectively. There was $48,945 insubordinated retained interest at December 31, 2013 and there was no subordinated retained interest at December 31, 2012. There were no borrowings under thesecuritization facility recorded on the Consolidated128Balance Sheets at December 31, 2013 and $37,846 borrowings under the securitization facility recorded on the Consolidated Balance Sheets at December 31,2012. Also, a $37,846 decrease, a $37,846 increase, and a $200,000 decrease in the accounts receivable securitization facility for the years ended December31, 2013, 2012 and 2011, respectively, are reflected in the Net Cash Used In Financing Activities in the Consolidated Statement of Cash Flows. In accordancewith the facility agreement, the Company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.NOTE 11—PROPERTY, PLANT AND EQUIPMENT: December 31, 2013 2012Coal & Other Plant and Equipment$3,681,051 $3,414,940Intangible Drilling Cost1,937,336 1,550,297Proven Properties1,670,404 1,596,838Unproven Properties1,463,406 1,266,017Coal Properties and Surface Lands1,404,056 1,164,107Gathering Equipment1,058,008 1,006,882Wells and Related Equipment688,548 492,364Airshafts397,466 366,054Leased Coal Lands393,372 529,758Coal Advance Mining Royalties381,348 381,343Mine Development354,607 262,511Other Gas Assets126,239 82,217Gas Advance Royalties22,668 8,229Total Property, Plant and Equipment13,578,509 12,121,557Less Accumulated Depreciation, Depletion and Amortization4,136,247 3,613,499Total Net Property, Plant and Equipment$9,442,262 $8,508,058The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yetcommenced and therefore, are not being amortized for the years ended December 31, 2013 and 2012, respectively. December 31, 2013 2012Unproven gas properties $1,487,166 $1,266,017Coal properties 273,242 317,676Mine Development 238,356 145,940Leased coal lands 99,506 118,697Coal advance mining royalties 48,043 55,749Airshafts 38,794 21,866Gas advance royalties 22,668 8,229 Total $2,207,775 $1,934,174As of December 31, 2013 and 2012, plant and equipment includes gross assets under capital lease of $96,015 and $93,745, respectively. For theyears ended December 31, 2013 and 2012, 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, 2013 and 2012, the Gas segment also maintains a capital lease for vehicles of $10,652 and $9,248,respectively, which are included in Other gas assets. For the years ended December 31, 2013 and 2012, the All Other segment maintains capital leases forvehicles and computer equipment of $18,444 and $17,578, respectively, which are included in Coal and other plant and equipment. Accumulatedamortization for capital leases was $50,371 and $44,726 at December 31, 2013 and 2012, respectively. Amortization expense for capital leases is included inDepreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 15–Leases for further discussion of capital leases.129Industry Participation AgreementsCONSOL Energy has two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completioncarries for our retained interests.On October 21, 2011, CNX Gas Company, a wholly owned subsidiary of CONSOL Energy, completed a sale to Hess Ohio Developments, LLC(Hess) a 50% interest in nearly 200 thousand net Utica Shale acres in Ohio. Cash proceeds related to this transaction were $54,254, which were net of$5,719 in transaction fees. Additionally, CONSOL Energy and Hess entered into a joint development agreement pursuant to which Hess agreed to payapproximately $534,000 in the form of a 50% drilling carry of certain CONSOL Energy working interest obligations as the acreage is developed. The net gainon the transaction was $53,095 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011.CONSOL Energy and Hess have agreed to focus their development efforts on six core counties in southeastern Ohio, in which the joint venture holdsapproximately 73,000 mostly fee acres. To this end, the parties have agreed to pursue the sale of approximately 63,000 acres outside of the focus areas. Inaddition, as previously disclosed, based on title work performed by Hess as part of the title defect process, we believe that there are chain of title issues withrespect to approximately 39,000 of the joint venture acres representing approximately $153,000 of carry, most of which likely cannot be cured. These acres,together with another 26,000 acres of allegedly defective acres have been reassigned to CONSOL Energy. CONSOL Energy may elect to cure the alleged defectsrelated to these acres and develop them, or sell the acres for its own account. After taking into account the reassignment of approximately 65,000 acres, theparties have agreed that the total carry remaining after these adjustments is $335,000. The loss of these Utica Shale acres will not have a material impact on theCompany's financial statements. 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. In September 2011, cash proceeds of $485,464 were received related tothis transaction, which were net of $34,998 transaction fees. Additionally, a note receivable was recognized related to the two additional cash payments to bereceived on the first and second anniversary of the transaction closing date. In September 2013, cash proceeds of $327,964 were received related to the secondanniversary note receivable. In September 2012, cash proceeds of $327,964 were received related to the first anniversary note receivable. During December2011, an additional receivable of $16,703 and a payable of $980 were recorded for closing adjustments and were included in Accounts and Notes Receivable -Other and Accounts Payable, respectively. Adjusted cash proceeds of $15,598 related to the additional receivable were received in April 2012. The net loss onthe transaction was $64,142 and was recognized in the Consolidated Statements of Income as Other Income for the year ended December 31, 2011. As part ofthe transaction, CNX Gas Company also received a commitment from Noble to pay one-third of the Company's working interest share of certain drilling andcompletion costs, up to approximately $2,100,000 with certain restrictions. These restrictions include the suspension of carry if average Henry Hub naturalgas prices are below $4.00 per million British thermal units (MMbtu) for three consecutive months. The carry is currently suspended and will remainsuspended until average natural gas prices are above $4.00/MMbtu for three consecutive months. Restrictions also include a $400,000 annual maximum onNoble'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, 2011Total Revenue and Other Income $6,073,904Earnings Before Income Taxes $775,807Net Income Attributable to CONSOL Energy Inc.Shareholders $623,114Basic Earnings Per Share $2.75Dilutive Earnings Per Share $2.72130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.Under our joint venture agreement with Noble, Noble had the right to perform due diligence on the title to the oil and gas interests which we conveyedto them and to assert that title to the acreage is defective. CONSOL Energy could then review and respond to the asserted title defects, or cure them, andultimately, if the claim is not resolved, either party could submit the defect to an arbitrator for resolution. We have completed our review of the title defect noticeasserted by Noble, and working in collaboration with them, we have addressed defects with respect to approximately 87,851 gross deal acres, having a carryvalue of approximately $551,000, and successfully resolved such defects to the satisfaction of both parties. We have conceded defects which have anaggregate value of approximately $216,000 in excess of the applicable deductibles and the carry payable by Noble Energy to CONSOL Energy has beenreduced by this amount. The impact of these conceded defects was $23,058 and $3,526 of expense for the years ended December 31, 2013 and 2012,respectively, and is included in Cost of Goods Sold and Other Charges in the Consolidated Statements of Income. The parties have resolved substantially alloutstanding asserted defects.The following table provides information about our industry participation agreements as of December 31, 2013: Industry Industry Participation Participation DrillingShale Agreement Agreement CarriesPlay Partner Date RemainingMarcellus Noble September 30, 2011 $1,873,785Utica Hess October 21, 2011 $230,353NOTE 12—SHORT-TERM NOTES PAYABLE:CONSOL Energy's $1,000,000 Senior Secured Credit Agreement, as amended by Amendment No. 1 dated December 5, 2013, expires April 12, 2016.The amendment reduced the availability from $1,500,000 to $1,000,000 resulting in an acceleration of previously deferred financing charges of $3,195during the year ended December 31, 2013. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries.CONSOL Energy's credit facility allows for up to $1,000,000 of borrowings and letters of credit. CONSOL Energy can request an additional $250,000increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earningsbefore interest, taxes, depreciation, depletion and amortization (Adjusted EBITDA), measured quarterly. The facility includes a minimum interest coverageratio covenant of no less than 1.50 to 1.00, measured quarterly through March 30, 2015 and 2.00 to 1.00 thereafter. The interest coverage ratio was 2.21 to 1.00at December 31, 2013. The facility also includes a senior secured leverage ratio covenant of not more than 2.00 to 1.00, measured quarterly. The senior securedleverage ratio was less than 1.00 to 1.00 at December 31, 2013. 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, 2013, the $1,000,000 facility had no borrowings outstanding and $206,988 of letters of credit outstanding, leaving$793,012 of capacity available for borrowings and the issuance of letters of credit. At December 31, 2012, the former $1,500,000 facility had no borrowingsoutstanding and $100,292 of letters of credit outstanding, leaving $1,399,708 of capacity available for borrowings and the issuance of letters of credit.CNX Gas Corporation's (CNX Gas) $1,000,000 Senior Secured Credit Agreement expires April 12, 2016. The facility is secured by substantially all ofthe assets of CNX Gas and its subsidiaries. CNX Gas' credit facility allows for up to $1,000,000 of borrowings and letters of credit. CNX Gas can request anadditional $250,000 increase in the aggregate borrowing limit amount. Fees and interest rate spreads are based on the percentage of facility utilization,measured quarterly. Covenants in the facility limit CNX Gas' ability to dispose of assets, make investments, pay dividends and merge with anothercorporation. The credit facility allows investments in joint ventures for the development and operation of gas gathering systems and provides for $600,000 ofloans, advances and dividends from CNX Gas to CONSOL Energy. Investments in CONE are unrestricted. The facility includes a maximum leverage ratiocovenant of not more than 3.50 to 1.00, measured quarterly. The leverage ratio was 0.61 to 1.00 at December 31, 2013. The facility also includes a minimuminterest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 25.33 to 1.00 at December 31, 2013. At December 31, 2013, the$1,000,000 facility had no borrowings outstanding and $87,643 of letters of credit outstanding, leaving $912,357 of capacity available for borrowings andthe issuance of letters of credit. At December 31, 2012, the $1,000,000 facility had no borrowings outstanding131and $70,203 of letters of credit outstanding, leaving $929,797 of capacity available for borrowings and the issuance of letters of credit. CONSOL Energy entered into an interim funding arrangement for longwall shields. At December 31, 2012, CONSOL Energy had a note payable of$25,073 related to this funding arrangement. The interim funding arrangement bore a weighted average interest rate of 2.46% as of December 31, 2012. Therewere no interim funding agreements outstanding at December 31, 2013.NOTE 13—OTHER ACCRUED LIABILITIES: December 31, 2013 2012Subsidence liability $98,573 $88,939Accrued interest 63,600 63,687Accrued payroll and benefits 38,953 39,172Short-term incentive compensation 30,371 28,744Uncertain income tax positions 28,530 2,100Accrued other taxes 26,305 35,943Other 122,902 144,352Current portion of long-term liabilities: Postretirement benefits other than pensions 60,847 58,452Mine closing 30,320 25,081Gas well closing 23,971 9,729Workers' compensation 13,628 9,176Reclamation 9,552 20,582Pneumoconiosis benefits 9,212 8,838Salary retirement 4,593 6,937Long-term disability 4,340 4,016Total Other Accrued Liabilities $565,697 $545,748NOTE 14—LONG-TERM DEBT: December 31, 2013 2012Debt: 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 value250,000 250,000MEDCO revenue bonds in series due September 2025 at 5.75%102,865 102,865Advance royalty commitments (7.93% and 7.43% weighted average interest rate for December 31, 2013and 2012, respectively)11,182 19,103Other long-term notes maturing at various dates through 2031 (total value of $5,923 and $7,300 lessunamortized discount of $1,050 and $1,542 at December 31, 2013 and December 31,2012, respectively).4,873 5,758 3,118,920 3,127,726Less amounts due in one year *2,957 4,126Long-Term Debt$3,115,963 $3,123,600* Excludes current portion of Capital Lease Obligations of $8,498 and $8,358 at December 31, 2013 and December 31, 2012, respectively.132Annual undiscounted maturities on long-term debt during the next five years are as follows:Year ended December 31,Amount2014$3,36420154,27620163,45720171,502,48420181,403Thereafter1,609,159 Total Long-Term Debt Maturities$3,124,143In August 2011, CONSOL Energy paid $16,090 which was the remaining principal balance on the 6.10% Notes due December 2012. The early debtretirement was completed 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 15—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, 2013, are as follows: Capital Operating Leases LeasesYear Ended December 31, 2014 $12,059 $90,5652015 10,984 85,2252016 9,842 73,1582017 8,758 66,5362018 8,128 41,221Thereafter 21,272 81,321Total minimum lease payments $71,043 $438,026Less amount representing interest (0.63% – 7.36%) 14,949 Present value of minimum lease payments 56,094 Less amount due in one year 8,498 Total Long-Term Capital Lease Obligation $47,596 Rental expense under operating leases was $90,128, $83,064, and $75,696 for the years ended December 31, 2013, 2012 and 2011, respectively.At December 31, 2013, certain of the above operating leases for mining equipment were subleased to third parties. The following represents theminimum rental payments for those operating subleases: 2014 2015 2016 2017 2018 Thereafter Total$33,084 $33,084 $33,084 $26,685 $26,685 $13,343 $165,965 133CONSOL Energy leases certain owned mining equipment to a third party under operating leases. The owned equipment included in gross property,plant and equipment was $53,484, with no accumulated depreciation at December 31, 2013. At December 31, 2013, scheduled minimum rental payments for operating leases related to this equipment were as follows: 20142015 2016 2017 2018 Thereafter Total$8,561 $8,561 $7,637 $4,496 $2,992 $2,328 $34,575 NOTE 16—PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all salaried employees. The benefits for these plans arebased primarily on years of service and employees' pay near retirement. CONSOL Energy's salaried plan allows for lump-sum distributions of benefits earnedup until December 31, 2005, at the employees' election. The Restoration Plan was frozen effective December 31, 2006 and was replaced prospectively with theCONSOL Energy Supplemental Retirement Plan. CONSOL Energy's Restoration Plan allows only for lump-sum distributions earned up until December 31,2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas. The Supplemental Retirement Planwas frozen effective December 31, 2011 for certain employees and was replaced prospectively with the CONSOL Energy Defined Contribution RestorationPlan.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 or non-represented hourly employees hired before January 1, 2007, the eligibility requirement is either age 55with 20 years of service or age 62 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 increasesof up to 6% will be shared by CONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of6% will be the responsibility of the participants. In 2012, the salaried OPEB plan was amended to reduce medical and prescription drug benefits as of January1, 2014. The plan amendment calls for a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The amount ofthe contribution will be dependent on several factors, and the money in the account can be used to help pay for a commercial medical plan, Medicare Part B orPart D premiums, and other qualified medical expenses. Employees who work or worked in corporate or operational support positions at retirement and whoare age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug benefits described aboveupon meeting the eligibility requirements at retirement. Employees who work or worked in corporate or operational support positions who are under age 50 atDecember 31, 2013 will receive no retiree medical or prescription drug benefits. In addition, any salaried or non-represented hourly employees that were hired orrehired effective January 1, 2007 or later and do not work in a corporate or operational support position are not eligible for retiree health benefits. In lieu oftraditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medical spending allowance of $2,250 peryear for each year of service at retirement.On March 31, 2012, the salaried OPEB plan was remeasured to reflect the announced plan amendment, which is described above. The remeasurementreflected the reduction in benefits and the change in discount rate to 4.57% at March 31, 2012 from 4.51% at December 31, 2011. The remeasurement resultedin an $80,571 reduction in the OPEB liability with a corresponding adjustment of $50,276 in other comprehensive income, net of $30,295 in deferred taxes.The change resulted in a $9,425 reduction in OPEB expense compared to what was originally expected to be recognized for the year ended December 31, 2012.The OPEB liability includes $3,000 and $12,400 as of December 31, 2013 and 2012, respectively, due to the PPACA reform legislation; in particular,the estimated impact of the potential excise tax beginning in 2018. The estimated liability for the excise tax was calculated using the following assumptions:testing pre-Medicare and Medicare covered retirees on a combined basis; assuming individual participants have an average claim cost and future healthcaretrend assumptions equal to those used in the year-end valuation; assuming the 2018 tax threshold amount to increase for inflation in later years. Theseassumptions may change once additional guidance becomes available. The 2013 and 2012 OPEB liability also includes the estimated impact of PPACAlegislation regarding the fees to support the Transitional Reinsurance Program. Due to the fact that the state-based exchanges are expected to incur losses duringtheir first few years of existence, the legislation provides for a temporary fee on health insurance issuers and self-insured group health plans that will be used tosupport these exchanges. The fee is payable for plan years 2014 through 2016. The fee for 2014 is $63 per covered pre-Medicare person, and is estimated todrop to $42 and $26 per covered pre-65 person in 2015 and 2016, respectively.134According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lumpsum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the projected service cost and interestcost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the year ended December 31, 2013. Accordingly,CONSOL Energy recognized expense of $39,482 for the year ended December 31, 2013 in Costs of Goods Sold and Other Operating Charges in theConsolidated Statement of Income. The settlement charges represented a pro rata portion of the net unrecognized loss based on the percentage reduction in theprojected benefit obligation due to the lump sum payments. The settlement charges noted above also resulted in remeasurements of the pension plan throughout2013.On December 5, 2013, CONSOL Energy completed the sale of its Consolidation Coal Company and certain other subsidiaries to Murray EnergyCorporation. As a result of the sale, the obligations for certain participants of the OPEB Plan are the primary responsibility of Murray Energy. This reducedCONSOL Energy's OPEB liability by $1,891,057 at December 31, 2013. These plan settlements resulted in adjustments of $339,318 in OtherComprehensive Income, net of $203,610 in deferred taxes at December 31, 2013. As the result of corporate staffing reductions associated with the sale, thePension and OPEB plans also recognized curtailment gains of $374 and $39,650 for the year ended December 31, 2013. The curtailment gains resulted inadjustments of $231 and $24,515 in Other Comprehensive Income, net of $143 and $15,135 in deferred taxes for the Pension Plan and the OPEB plan,respectively, at December 31, 2013.135The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2013 and 2012, is as follows: Pension Benefits Other Postretirement Benefits at December 31, at December 31, 2013 2012 2013 2012Change in benefit obligation: Benefit obligation at beginning of period $953,102 $857,352 $3,018,172 $3,242,200Service cost 20,865 20,466 18,680 18,817Interest cost 36,829 37,586 111,687 135,695Actuarial loss (gain) (82,718) 90,502 (73,632) (131,150)Plan amendments — — — (80,570)Plan curtailments (6,551) — — —Plan settlements (86,925) — (1,891,057) —Participant contributions — — 6,150 5,651Benefits and other payments (21,958) (52,804) (168,026) (172,471)Benefit obligation at end of period $812,644 $953,102 $1,021,974 $3,018,172 Change in plan assets: Fair value of plan assets at beginning of period $728,161 $582,571 $— $—Actual return on plan assets 94,084 87,935 — —Company contributions 55,469 110,459 161,876 166,820Participant contributions — — 6,150 5,651Benefits and other payments (21,958) (52,804) (168,026) (172,471)Plan Settlements (86,925) — — —Fair value of plan assets at end of period $768,831 $728,161 $— $— Funded status: Noncurrent assets $9,032 $— $— $—Current liabilities (4,593) (6,937) (60,847) (58,452)Noncurrent liabilities (48,252) (218,004) (961,127) (882,600)Liabilities of discontinued operations — — — (2,077,120)Net obligation recognized $(43,813) $(224,941) $(1,021,974) $(3,018,172) Amounts recognized in accumulated other comprehensiveincome consist of: Net actuarial loss $286,637 $495,511 $433,073 $1,116,051Prior service credit (4,629) (6,614) (34,086) (104,288)Net amount recognized (before tax effect) $282,008 $488,897 $398,987 $1,011,763136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, 2013 2012 2011 2013 2012 2011Components of net periodic benefit cost: Service cost$20,865 $20,466 $17,457 $18,680 $18,817 $13,677Interest cost36,829 37,586 37,744 111,687 135,695 179,739Expected return on plan assets(51,814) (46,157) (38,522) — — —Amortization of prior service (credits)(1,611) (1,630) (666) (30,552) (51,828) (46,397)Recognized net actuarial loss37,853 47,834 38,102 66,417 80,875 105,364Curtailment gain(374) — — (39,650) — —Settlement loss (gain)39,482 — — (1,348,129) — —Net periodic benefit cost (credit)$81,230 $58,099 $54,115 $(1,221,547) $183,559 $252,383Expenses (income) attributable to discontinued operations included in the net periodic cost (credit) above (including settlements and curtailmentsassociated with the sale of CCC and certain subsidiaries to Murray Energy) were $8,231, $11,587, and $10,693 for the years ended December 31, 2013,2012, and 2011, respectively, for the Pension Plans and were $(1,293,975), $101,418, and $140,524 for the years ended December 31, 2013, 2012, and2011, respectively, for the Other Postretirement Benefits Plan.Amounts included in accumulated other comprehensive loss, expected to be recognized in 2014 net periodic benefit costs: Other Pension Postretirement Benefits BenefitsPrior Service (credit) recognition $(1,384) $(8,784)Actuarial loss recognition $23,564 $25,474The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets: As of December 31, 2013 2012Projected benefit obligation $52,845 $953,102Accumulated benefit obligation $50,820 $895,493Fair value of plan assets $— $728,161Assumptions: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, 2013 2012 2013 2012Discount rate 4.87% 4.00% 4.88% 4.05%Rate of compensation increase 4.23% 3.77% — —137The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. TheCompany-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds usedin the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows,and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans'.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, 2013 2012 2011 2013 2012 2011Discount rate 4.00% 4.50% 5.30% 4.05% 4.51% 5.33%Expected long-term return on plan assets 7.75% 8.00% 8.00% — — —Rate of compensation increase 3.77% 3.82% 3.66% — — —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, 2013 2012 2011Health care cost trend rate for next year 6.17% 6.30% 6.85%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 2026 2026Assumed 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 $17,296 $(14,297)Effect on accumulated postretirement benefit obligation $123,355 $(103,788)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 $(1,797) $1,798Other postemployment benefits costs (decrease) increase $(3,690) $3,830Plan 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 31 percent U.S. equity securities, 20 percent non-U.S. equity securities, 9 percent global equity securities, and 40percent fixed income. Both the equity and fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarilyinvested in Mercer Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities beingderived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments,138including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backedobligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within thefixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest ratesensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on theTrust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extendthe duration of the overall fixed income portfolio; however they may not be used for speculative purposes. All or a portion of the assets may be invested inmutual funds or other comingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in adiversified manner; and have management and/or oversight by an Investment Advisor registered with the SEC. The Retirement Board, as appointed by theCONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments incapital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.The fair values of plan assets at December 31, 2013 and 2012 by asset category are as follows: Fair Value Measurements at December 31, 2013 Fair Value Measurements at December 31, 2012 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 $634 $634 $— $— $610 $610 $— $—US Equities (a) 14 14 — — 11 11 — —Mercer Collective Trusts US Large Cap Growth Equity (b) 56,006 — 56,006 — 63,726 — 63,726 —US Large Cap Value Equity (c) 56,802 — 56,802 — 64,381 — 64,381 —US Small/Mid Cap Growth Equity(d) 28,530 — 28,530 — 26,406 — 26,406 —US Small/Mid Cap Value Equity (e) 28,552 — 28,552 — 26,411 — 26,411 —US Core Fixed Income (f) 35,533 — 35,533 — 38,045 — 38,045 —Non-US Core Equity (g) 126,712 — 126,712 — 146,009 — 146,009 —Emerging Markets Equity (h) 29,778 — 29,778 — 33,541 — 33,541 —Global Low Volatility Equity (i) 70,138 — 70,138 — — — — —US Long Duration Investment GradeFixed Income (j) 55,593 — 55,593 — 39,925 — 39,925 —US Long Duration Fixed Income (k) 33,489 — 33,489 — 30,675 — 30,675 —US Large Cap Passive Equity (l) 75,468 — 75,468 — 81,067 — 81,067 —US Passive Fixed Income (m) 20,287 — 20,287 — 20,415 — 20,415 —US Long Duration Passive FixedIncome (n) 34,108 — 34,108 — 29,483 — 29,483 —US Ultra Long Duration FixedIncome (o) 7,656 — 7,656 — 34,595 — 34,595 —US Active Long CorporateInvestment (p) 105,412 — 105,412 — 92,861 — 92,861 —Long Strips Fixed Income (q) 2,022 — 2,022 — — — — —Opportunistic Fixed Income (r) 2,097 — 2,097 — — — — —Total $768,831 $648 $768,183 $— $728,161 $621 $727,540 $—__________(a)This category includes investments in US common stocks and corporate debt.139(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 Mercer’s investment managementteam. 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 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 Mercer’s investment management team. Thestrategy is benchmarked to the Russell 1000 Value Index.(d)This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets 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 Mercer’s investment management team. Thesmaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on anongoing 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 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 Mercer’s investment management team. Thesmaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on anongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.(f)This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks toachieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio durationis targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of directinvestment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented byMercer’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.(g)This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to emerging markets. The strategytargets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary activemanagers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emergingmarkets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer’sinvestment management team. The strategy is benchmarked to the MSCI EAFE Index.(h)This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors andseeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selectionand allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI EmergingMarkets Index.(i)This category invests in companies operating in developed markets, globally. The strategy targets a diversified portfolio of equity securities issued bycompanies which the investment managers believe will exhibit less volatility in their price performance relative to the broad equity market asdescribed by the MSCI World Index. The strategy is benchmarked to the MSCI World Index.(j)This category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managedU.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing forshort term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long CreditIndex and 10% to the Barclays Capital Long Treasury.(k)This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs.The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fundselection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to theBarclays Capital U.S. Long Government/Credit Index.(l)This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.(m)This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlyingpassive investments are benchmarked to the Barclays Capital Aggregate Index.140(n)This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.(o)This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra longduration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rateswaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized,resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return inexcess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align theduration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.(p)This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10%weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk throughactive management while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to theBarclays Capital U.S. Long Corporate Index and 10% to the Barclay’s Capital Long Treasury.(q)This category invests primarily in long dated US Treasury STRIPS often with maturities greater than 20 years. The strategy and its underlyingpassive investments are benchmarked to the Barclays Capital U.S. 20+ Year STRIPS Index.(r)This category invests primarily in fixed income securities from issuers either located in developing/emerging markets or those rated below investmentgrade (high yield), globally, The strategy is benchmarked to a blended index of 50% JP Morgan Government Bond Index Emerging Markets GlobalDiversified and 50% Bank of America/Merrill Lynch Global High Yield Index.There are no investments in CONSOL Energy stock held by these plans at December 31, 2013 or 2012.There are no assets in the other postretirement benefit plans at December 31, 2013 or 2012.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 $25,000 - $35,000 to our pension plan trust in 2014. Pension benefit payments are primarily funded from the trust.CONSOL Energy does not expect to contribute to the other postemployment plan in 2014. 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 Benefits2014 $90,347 $60,8472015 $50,080 $62,9142016 $48,952 $65,4932017 $49,415 $67,6232018 $50,741 $68,395Year 2019-2023 $262,986 $338,544NOTE 17—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.141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. Actuarial gains associated with workers' compensation haveresulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident ratesthan our assumptions.On December 5, 2013, CONSOL Energy completed the sale of its Consolidation Coal Company and certain other subsidiaries to Murray EnergyCorporation. As a result of the sale, the obligations for certain participants of the CWP and Workers' Compensation plans now belong to Murray Energy. Thisreduced CONSOL Energy's CWP and Workers' Compensation liabilities by $49,652 and $105,308 respectively at December 31, 2013. These plansettlements resulted in adjustments of $43,892 and $13,768 in Other Comprehensive Income, net of $26,337 and $8,262 in deferred taxes for CWP andWorkers' Compensation, respectively, at December 31, 2013. The settlements were included in the results of discontinued operations. CWP Workers' Compensation at December 31, at December 31, 2013 2012 2013 2012Change in benefit obligation: Benefit obligation at beginning of period $184,079 $183,580 $179,589 $174,069State administrative fees and insurance bond premiums — — 5,324 6,727Service, legal and administrative cost 8,168 7,711 15,943 17,126Interest cost 7,031 7,964 6,401 7,113Actuarial (gain) loss (18,020) (3,919) 11,806 6,754Benefits paid (10,423) (11,257) (28,659) (32,200)Settlements (49,652) — (105,308) —Benefit obligation at end of period $121,183 $184,079 $85,096 $179,589 Current liabilities $(9,212) $(8,838) $(13,628) $(9,176)Noncurrent liabilities (111,971) (114,136) (71,468) (60,396)Liabilities of discontinued operations — (61,105) — (110,017)Net obligation recognized $(121,183) $(184,079) $(85,096) $(179,589) Amounts recognized in accumulated other comprehensiveincome consist of: Net actuarial gain $(80,363) $(148,955) $(13,569) $(44,535)Net amount recognized (before tax effect) $(80,363) $(148,955) $(13,569) $(44,535)142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, 2013 2012 2011 2013 2012 2011Service cost$8,168 $7,711 $7,620 $15,943 $17,126 $20,015Interest cost7,031 7,964 9,330 6,401 7,113 8,238Amortization of prior service cost— (395) (728) — — —Recognized net actuarial gain(16,384) (19,338) (21,182) (2,630) (3,944) (3,907)State administrative fees and insurance bondpremiums— — — 5,324 6,727 7,035Settlement gain(119,881) — — (121,838) — —Net periodic cost (credit)$(121,066) $(4,058) $(4,960) $(96,800) $27,022 $31,381(Income) expenses attributable to discontinued operations included in the net periodic cost (credit) (including settlements and curtailments associated withthe sale of CCC and certain subsidiaries to Murray Energy) above were $(120,496), $(2,374), and $(2,887) for the years ended December 31, 2013, 2012,and 2011, respectively, for CWP and $(113,097), $10,132, and $12,722 for the years ended December 31, 2013, 2012, and 2011, respectively, forWorkers' Compensation.Amounts included in accumulated other comprehensive income, expected to be recognized in 2014 net periodic benefit costs: Workers' CWP Compensation Benefits BenefitsPrior Service benefit recognition $— $—Actuarial gain recognition $(6,196) $(382)Assumptions:The weighted-average discount rates 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, 2013 2012 2011 2013 2012 2011Benefit obligations 4.75% 4.03% 4.46% 4.57% 3.95% 4.40%Net periodic (benefit) cost 4.03% 4.46% 5.21% 3.95% 4.40% 5.13% The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. TheCompany-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds usedin the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows,and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans'.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) $585 $(530)Workers' Compensation costs (decrease) increase $(379) $398143Cash Flows:CONSOL Energy does not intend to make contributions to the CWP or Workers' Compensation plans in 2014. 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 Benefits2014 $9,211 $18,635 $13,628 $5,0072015 $9,204 $18,479 $13,347 $5,1322016 $9,185 $18,602 $13,341 $5,2612017 $9,163 $18,815 $13,423 $5,3922018 $9,156 $19,000 $13,473 $5,527Year 2019-2023 $45,090 $99,249 $69,471 $29,778NOTE 18—OTHER EMPLOYEE BENEFIT PLANS: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 Plan. In connection withthe sale of Consolidation Coal Company and certain subsidiaries, CONSOL Energy retained responsibility for the contributions to these two funds.CONSOL Energy accounts 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 Plan 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 $11,435, $12,358, and $13,609 for the years ended December 31, 2013, 2012 and2011, respectively. Based on available information at December 31, 2013, CONSOL Energy's obligation for the Act is estimated to be approximately$120,394.Pursuant to the provisions of the Tax Relief and Healthcare Act of 2006 (The 2006 Act) and the 1992 Benefit Plan, CONSOL Energy is required toprovide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Benefit Plan whoare attributable to CONSOL Energy, plus all individuals receiving benefits from an individual employer plan maintained by CONSOL Energy who areentitled to receive such benefits. In accordance with the 2006 Act and the 1992 Benefit Plan, the outstanding letters of credit to secure our obligation were$60,741, $63,614, and $67,349 for years ended December 31, 2013, 2012 and 2011, respectively. The 2013, 2012 and 2011 security amounts were basedon the annual cost of providing health care benefits and included a reduction in the number of eligible employees.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 19–Stock Based Compensation for further discussion of CONSOL Energy's equity incentive plans.Investment Plan:CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company matchingcontribution was 6% of eligible compensation contributed for all non-represented employees except for those employees of Fairmont Supply Company, whosecontribution remains a match of 50% of the first 12% of eligible compensation contributed by the employee. Total payments and costs were $23,748,$24,127, and $23,394 for the years ended December 31, 2013, 2012 and 2011, respectively.144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, 2013 2012 2011Benefit (Credit) Cost $(687) $6,122 $6,439Discount rate assumption used to determine net periodic benefit costs 3.04% 3.62% 4.04%Expenses attributable to discontinued operations included in the net periodic cost (credit) above were $2,073, $1,816, and $2,048 for the years endedDecember 31, 2013, 2012, and 2011.Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities–Other and Other Accrued Liabilities and amounted to$20,425 and $24,144 at December 31, 2013 and 2012, respectively. On December 5, 2013, CONSOL Energy completed the sale of its Consolidation CoalCompany and certain other subsidiaries to Murray Energy Corporation. As a result of the sale, the obligations for certain participants of the Long-TermDisability plan now belong to Murray Energy. This reduced CONSOL Energy's Long-Term Disability liability by $10,140 at December 31, 2013. These plansettlements resulted in adjustments of $1,338 in Other Comprehensive Income, net of $803 in deferred taxes at December 31, 2013.2012 Voluntary Severance Incentive Program (VSIP):CONSOL Energy offered a VSIP to active salaried corporate and operation support employees with 30 years of service, or more. Under this program,eligible employees who accepted the offer received a severance payment equal to one year's salary and any 2013 accrued vacation earned as of December 31,2012. Approximately 100 employees volunteered for the program. Severance and vacation pay costs of $13,304 were accrued for the program at December 31,2012, and were paid in 2013.NOTE 19—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. In2012, the Board of Directors approved an increase in the total number of shares by 8,000,000 bringing the total number of shares of common stock that can becovered by grants to 31,800,000. At December 31, 2013, 6,072,413 shares are available for all awards. The Plan provides that the aggregate number of sharesavailable for issuance under the Plan will be reduced by one share for each share issued in settlement of stock options. The Plan, as amended on May 1,2012, provides the aggregate number of shares available for issuance under the Plan will be reduced by 1.62 for each share issued in settlement ofPerformance Share Units (PSUs), Restricted Stock Units (RSUs), or CONSOL Stock Units (CSUs). No award of stock options may be exercised under theplan after 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 $56,987, $41,127 and $42,131 for the years ended December 31, 2013, 2012 and 2011, respectively. The relateddeferred tax benefit totaled $21,769, $15,464 and $15,841, for the years ended December 31, 2013, 2012 and 2011, 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. There were no options granted in 2013. Total fair value of options granted during the years endedDecember 31, 2012 and 2011 were $8,515 and $9,913, respectively. The fair value of share-based payment awards was estimated using the Black-Scholesoption pricing model with the following assumptions and weighted average fair values:145 December 31, 2012 2011Weighted average fair value of grants $14.58 $20.47Risk-free interest rate 0.73% 1.61%Expected dividend yield 1.18% 0.82%Expected forfeiture rate 2.00% 2.00%Expected volatility 54.80% 55.10%Expected term in years 4.40 4.26A 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, 2012 5,111,214 $36.54 Granted — $— Exercised (310,376) $11.99 Forfeited (23,612) $38.64 Balance at December 31, 2013 4,777,226 $38.12 4.20 $28,398Vested and expected to vest 4,765,963 $38.13 4.19 $28,398Exercisable at December 31, 2013 4,344,749 $38.45 3.76 $28,839These stock options will expire 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 4,529,216 stock options outstanding under the Equity IncentivePlan. Additionally, there are 192,934 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 53,895 stock options outstanding under these grants. Thevesting of all options, including performance options, will accelerate in the event of death, disability or retirement and may accelerate upon a change in controlof CONSOL Energy.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, 2013, 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, 2013. 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, 2013, 2012 and 2011 was $6,820, $18,562and $18,049, respectively.Cash received from option exercises for the years ended December 31, 2013, 2012 and 2011 was $3,720, $8,383 and $9,033, respectively. The taximpact from option exercises totaled $2,929, $8,678, and $8,281, for the years ended December 31, 2013, 2012 and 2011, respectively. This excess taxbenefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.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, 2013, 2012 and 2011 was $20,687, $26,426 and $24,882, respectively. Thetotal fair value of shares vested during the years ended December 31, 2013, 2012 and 2011 was $37,002, $23,097 and $16,496, respectively. The followingrepresents the unvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant:146 Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2012 1,326,953 $40.39Granted 654,656 $31.60Vested (930,390) $39.77Forfeited (169,649) $32.93Nonvested at December 31, 2013 881,570 $35.95Under 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, 2013, 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, 2013, 2012 and 2011 was $1,270, $16,794 and $11,648,respectively. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) atthe date of grant: Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2012 702,194 $50.76Granted 40,514 $31.35Vested (159,228) $68.45Nonvested at December 31, 2013 583,480 $38.19Under 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. Theannual performance goals for the performance stock options include a gas cost goal and a gas production goal. Achievement of the gas production goal for theyear ended December 31, 2012 did not occur. A reversal of compensation expense of $1,671 was recognized in Cost of Goods Sold and Other OperatingCharges for the year ended December 31, 2012. The achievement of all goals is believed to be probable at December 31, 2013. The total fair value ofperformance share options vested during the year ended December 31, 2013, 2012, 2011 was $1,650, $6,599, $3,299. The following represents theunvested performance options 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, 2012 401,392 $16.44Vested (100,349) $16.44Nonvested at December 31, 2013 301,063 $16.44Under the Equity Incentive Plan, CONSOL Energy granted certain employees CONSOL Stock Unit Awards. These awards entitle the holder toreceive shares 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, 2013, the achievement of the market and performance goals is believed to beprobable. The total fair value of CONSOL Stock Units granted during the year ended December 31, 2013 was $28,381. The following represents theunvested CONSOL Stock Unit awards and their corresponding fair value (based upon the closing share price) at the date of the grant:147 Number of Weighted Average Shares Grant Date Fair ValueNonvested at December 31, 2012 — —Granted 842,167 $33.70Forfeited (8,614) $33.39Nonvested at December 31, 2013 833,553 $33.70As of December 31, 2013, $20,508 of total unrecognized compensation cost related to all unvested stock-based awards is expected to be recognized overa weighted-average period of 1.79 years. When stock options are exercised and restricted and performance stock unit awards become vested, the issuances aremade from CONSOL Energy's common stock shares.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. See Note 2 - Discontinued Operations and Note - 3 Acquisitions and Dispositions.CONSOL Energy obtains capital lease arrangements for company used vehicles. For the years ended December 31, 2013, 2012 and 2011, CONSOLEnergy entered into non-cash capital lease arrangements of $4,178, $3,583, and $4,649, respectively.As of December 31, 2013, 2012 and 2011, CONSOL Energy purchased goods and services related to capital projects in the amount of $175,371,$63,051 and $61,690, respectively, that are included in accounts payable.During the year ended December 31, 2012, CONSOL Energy entered into a promissory note for $6,236 with the lessor of its former headquarters toreplace the existing operating lease.The following table shows cash paid during the year for: For the Years Ended December 31, 2013 2012 2011Interest (Net of Amounts Capitalized) $209,580 $212,364 $242,587Income Taxes $35,079 $121,245 $144,405NOTE 21—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:CONSOL Energy markets natural gas primarily to gas wholesalers, thermal coal, principally to electric utilities in the United States, Canada andWestern Europe and metallurgical coal to steel and coke producers worldwide.Concentration of credit risk is summarized below: December 31, 2013 2012Thermal coal utilities $154,738 $247,955Steel and coke producers 10,963 47,203Coal brokers and distributors 52,233 65,057Gas wholesalers 71,441 51,718Various other 43,199 16,395Total Accounts Receivable Trade (including Accounts Receivable—Securitized) $332,574 $428,328Accounts receivable from thermal coal utilities and steel and coke producers include amounts sold under the accounts receivable securitization facility.See Note 10–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, 2013, Xcoal Energy Resources and Duke Energy Carolinas each comprised over 10% of our revenues from continuingoperations. Coal sales to Xcoal Energy Resources were $495,242 and coal sales to Duke Energy148Carolinas were $346,424 during 2013. For the year ended December 31, 2012 and 2011, coal sales to Xcoal Energy Resources comprised over 10% of ourrevenues from continuing operations. Coal sales to Xcoal Energy Resources were $382,843 and $655,596 for the year ended December 31, 2012 and 2011,respectively.NOTE 22—FAIR VALUE OF FINANCIAL INSTRUMENTS:The financial instruments measured at fair value on a recurring basis are summarized below: Fair Value Measurements at December 31, 2013 Fair Value Measurements at December 31, 2012DescriptionQuoted Prices inActive Marketsfor IdenticalLiabilities(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3) Quoted Prices inActive Marketsfor IdenticalLiabilities(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3)Gas Cash Flow Hedges (Note 23)$— $65,449 $— $— $128,945 $—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 amounts reported in the balance sheets for restricted cash, both current and long-term approximates its fair value.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.The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows: December 31, 2013 December 31, 2012 CarryingAmount FairValue CarryingAmount FairValueCash and cash equivalents$327,420 $327,420 $21,862 $21,862Restricted cash (a)$— $— $68,673 $68,673Short-term notes payable$— $— $(25,073) $(25,073)Borrowings under securitization facility$— $— $(37,846) $(37,846)Long-term debt$(3,118,920) $(3,299,875) $(3,127,726) $(3,376,767)(a) The 2012 restricted cash balance includes $48,294 and $20,379 located in current assets and other assets of the Consolidated Balance Sheet, respectivelyNOTE 23—DERIVATIVE INSTRUMENTS: CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. The fair value of CONSOLEnergy's derivatives (natural gas price swaps) are based on intra-bank pricing models which utilize inputs that are either readily available in the publicmarket, such as natural gas forward curves, or can be corroborated from active markets or broker quotes. These values are then compared to the values givenby our counterparties for reasonableness. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteriaare met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item149are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in the fair value of the derivatives are reported inOther Comprehensive Income or Loss (OCI) on the Consolidated Balance Sheets and reclassified into Outside Sales on the Consolidated Statements of Incomein the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the currentperiod. CONSOL Energy currently utilizes only cash flow 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.None of our counterparty master agreements currently require CONSOL Energy to post collateral for any of its hedges. However, as stated in thecounterparty master agreements, if CONSOL Energy's obligations with one of its counterparties cease to be secured on the same basis as similar obligationswith the other lenders under the credit facility, CONSOL Energy would have to post collateral for hedges in a liabilities position in excess of definedthresholds. All of our derivative instruments are subject to master netting arrangements with our counterparties. CONSOL Energy recognizes all financialderivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis. Each of CONSOL Energy's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts.If early termination is elected, CONSOL Energy and the applicable counterparty would net settle all open hedge positions.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 sales from the underlying commodity. As of December 31,2013, the total notional amount of the Company’s outstanding natural gas swap contracts was 279.3 billion cubic feet. These swap contracts are forecasted tosettle through December 31, 2016 and meet the criteria for cash flow hedge accounting. As these contracts settle, the cash received and/or paid will be shownon the Consolidated Statements of Cash Flows as Changes in Prepaid Expenses, Changes in Other Assets, Changes in Other Operating Liabilities and/orChanges in Other Liabilities. Assuming no changes in price during the next twelve months, $30,333 of unrealized gain is expected to be reclassified from OtherComprehensive Income on the Consolidated Balance Sheets and into Outside Sales on the Consolidated Statements of Income, as a result of the grosssettlement of cash flow hedges. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.The gross fair value at December 31, 2013 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flowhedges, was an asset of $83,661 and a liability of $18,212. The total asset is comprised of $59,605 and $24,056 which were included in Prepaid Expenseand Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $12,327 and $5,885 which were included in OtherAccrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.The gross fair value at December 31, 2012 of CONSOL Energy's derivative instruments, which were all natural gas swaps and qualify as cash flowhedges, was an asset of $135,969 and a liability of $7,024. The total asset is comprised of $80,057 and $55,912 which were included in Prepaid Expenseand Other Assets, respectively, on the Consolidated Balance Sheets. The total liability is comprised of $970 and $6,054 which were included in OtherAccrued Liabilities and Other Liabilities, respectively, on the Consolidated Balance Sheets.The effect of derivative instruments in cash flow hedging relationships on the Consolidated Statements of Income and the Consolidated Statements ofStockholders' Equity net of tax were as follows:150 Year Ended December 31, 201320122011Natural Gas Price Swaps Beginning Balance – Accumulated OCI$76,761$151,780$46,087Gain recognized in Accumulated OCI$45,631$114,240$200,700Less: Gain reclassified from Accumulated OCI into Outside Sales$79,899$189,259$95,007Ending Balance – Accumulated OCI$42,493$76,761$151,780Gain recognized in Outside Sales for ineffectiveness $(4,645)$579$1,034There were no amounts recognized in earnings related to the amount excluded from the assessment of hedge effectiveness in 2013, 2012 or 2011.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 amounts 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 estimated,exceeds the aggregate amounts accrued for all lawsuits and claims by approximately $318,786.The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized. Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as adefendant in approximately 6,900 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Texas and Illinois. Because a verysmall percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pendingclaims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine howmany 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 of suchindemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protectionfrom these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Based on over 15 years of experience withthis litigation, we have established an accrual to cover our estimated liability for these cases. This accrual is immaterial to the overall financial position ofCONSOL Energy and was included in Other Accrued Liabilities on the Consolidated Balance Sheet. Past payments by Fairmont with respect to asbestoscases have not been material.Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia styled Hale v.CNX Gas Company, et. al. The lawsuit alleges that the plaintiff class consists of forced-pooled unleased gas owners whose gas ownership is in conflict, theVirginia Supreme Court and General Assembly have decided that coalbed methane (CBM) belongs to the owner of the gas estate, the Virginia Gas and Oil Actof 1990 unconstitutionally provides only a 1/8 net proceeds royalty to CBM owners for gas produced under the forced-pooled orders, and CNX GasCompany relied upon control of only the coal estate in force pooling the CBM notwithstanding decisions by the Virginia Supreme Court. The lawsuit seeks ajudicial 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 sinceproduction began) be distributed to the class members. The lawsuit also alleges CNX Gas Company failed to either pay royalties due to conflicting claimants,or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. The Magistrate Judge issued a Report and Recommendation in which she recommended that the District Judge decide that the deemedlease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty. The Magistrate Judge recommended against the dismissal of certain other claims.The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An amended complaint was filed, which added additional allegations thatinclude gas hedging receipts should have been used as the basis for royalty payments, severance tax should not be allowed as a post-151production deduction from royalties, and damages incurred because gas was produced prior to the entry of pooling orders. A motion to dismiss the AmendedComplaint was filed and denied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grantplaintiffs' Motion for Class Certification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The DistrictJudge heard argument on the Objections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report& Recommendation and certifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed aPetition asking the U.S. Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered anOrder deferring a ruling on the Petition; assigning the case to a merits panel; and, requesting full briefing of the class certification challenge. At the same time,Plaintiffs have filed Motions for Summary Judgment on the issue of “ownership” of the gas royalty escrow accounts and seeking an accounting. The FourthCircuit denied a Motion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge held argument on thesummary judgment motions for January 6, 2014. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. Wehave established an accrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and isincluded in Other Accrued Liabilities on the Consolidated Balance Sheet.Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in the United States District Court in Abingdon, Virginia styledAddison v. CNX Gas Company, et al. The lawsuit alleges that the plaintiff class consists of gas lessors whose gas ownership is in conflict. The lawsuitalleges that the Virginia Supreme Court and General Assembly have decided that the plaintiff owns the gas and is entitled to royalties held in escrow by theCommonwealth of Virginia or CNX Gas Company. The lawsuit also alleges CNX Gas Company failed to either pay royalties due these conflicting claimantlessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-productiondeductions. Plaintiff seeks a declaratory judgment regarding ownership, an accounting and compensatory and punitive damages for breach of contract;conversion; negligence (voluntary undertaking) for improperly asserting that conflicting ownership exists, negligence (breach of duties as an operator); breachof fiduciary duties; and unjust enrichment. The Magistrate Judge issued a Report and Recommendation recommending dismissing some claims and allowingothers to proceed. The District Judge affirmed the Magistrate Judge's recommendations in their entirety. An Amended Complaint was filed which added anadditional allegation that gas hedging receipts should have been used as the basis for royalty payments. A motion to dismiss those claims was filed and wasdenied. The Magistrate Judge issued a Report & Recommendation on June 5, 2013, recommending that the District Judge grant plaintiffs' Motion for ClassCertification. CNX Gas Company filed its extensive Objections to the Report & Recommendation on July 3, 2013. The District Judge heard argument on theObjections on September 12, 2013, and on September 30, 2013, entered an Order overruling the Objections, adopting the Report & Recommendation andcertifying the class with a modified class definition. CNX Gas believes this case cannot properly proceed as a class action and filed a Petition asking the U.S.Court of Appeals for the Fourth Circuit to review the class certification Order. On November 13, 2013, the Fourth Circuit entered an Order deferring a rulingon the Petition; assigning the case to a merits panel; and, requesting full briefing of the class certification challenge. At the same time, Plaintiffs have filedMotions for Summary Judgment on the issue of “ownership” of the gas royalty escrow accounts and seeking an accounting. The Fourth Circuit denied aMotion to Stay the trial court proceedings while it considers the class certification issues, and the District Judge held argument on the summary judgmentmotions for January 6, 2014. CONSOL Energy believes that the case has meritorious defenses and intends to defend it vigorously. We have established anaccrual to cover our estimated liability for this case. This accrual is immaterial to the overall financial position of CONSOL Energy and was included inOther Accrued Liabilities on the Consolidated Balance Sheet.The following royalty and land right lawsuits and claims include those for which a loss is reasonably possible, but not probable, and accordingly,no accrual has been recognized. These claims are influenced by many factors which prevent the estimation of a range of potential loss. These factors include,but are 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.Ratliff Litigation: On March 22, 2012, the Company was served with four complaints filed on May 31, 2011 by four individuals againstConsolidation Coal Company (CCC), Island Creek Coal Company (ICCC), CNX Gas Company, subsidiaries of CONSOL Energy, as well as CONSOLEnergy itself in the Circuit Court of Russell County, Virginia. The complaints seek damages and injunctive relief in connection with the deposit of water frommining activities at CCC's Buchanan Mine into nearby void spaces at some of the mines of ICCC. The suits allege damage to coal and coalbed methane andseek recovery in tort, contract and assumpsit (quasi-contract). The cases were removed to federal court, motions to dismiss152were filed by CCC, and then were voluntarily dismissed by the plaintiffs. On January 30, 2013, the four plaintiffs filed a single consolidated complaintagainst the same defendants in the United States District Court for the Western District of Virginia, alleging the same damage and theories of recovery forstorage of water in the mine voids ostensibly underlying their property. The suit seeks damages ranging from $4,000 to $8,000 plus punitive damages. Thedefendants have asserted Virginia's Mine Void Statute as a defense to plaintiffs claims and the plaintiffs have challenged the constitutionality of that statute.Based on Plaintiffs’ challenge, the Court on August 1, 2013, entered a Certificate pursuant to 28 USC Section 2304 notifying the Virginia Attorney Generalthat the Mine Void Statute had been called into question and advising the Commonwealth of its right to intervene in the proceedings for the limited purpose ofaddressing the constitutionality of the statute. To date, the Virginia Attorney General has not responded. CONSOL Energy intends to vigorously defend thesuit. Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 captioned Earl Kennedy (and others) v. CNX Gas Company andCONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas Company and CONSOL Energytrespassed and converted 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 soughtto overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking toappeal that dismissal. The suit also seeks a determination that the Pittsburgh 8 coal seam does not include the “roof/rider” coal. The court denied the plaintiff'ssummary judgment motion on that issue. The court held a bench trial on the “roof/rider” coal issue in November 2011 and ruled for CNX Gas Company andCONSOL Energy, holding that the “roof/rider” coal is included in the Pittsburgh 8 coal seam. The plaintiffs have indicated that they intend to appeal thatdecision. A Motion for Summary Judgment on all remaining counts was argued on January 10, 2014, and remains pending. Should the Motion be denied, atrial on the issue of whether a drilling that deviates from the coal seam results in damage to the gas owner is anticipated for first quarter 2014. CNX GasCompany and CONSOL Energy believe this lawsuit to be without merit and intends to vigorously defend it. Consequently, we have not recognized anyliability related to these actions.Rowland Litigation: Rowland Land Company filed a complaint in May 2011 against CONSOL Energy, CNX Gas Company, Dominion ResourcesInc., and EQT Production Company (EQT) in Raleigh County Circuit Court, West Virginia. Rowland is the lessor on a 33,000 acre oil and gas lease insouthern West Virginia. EQT was the original lessee, but farmed out the development of the lease to Dominion Resources in exchange for an overriding royalty.Dominion Resources sold the indirect subsidiary that held the lease to a subsidiary of CONSOL Energy on April 30, 2010. Subsequent to that acquisition, thesubsidiary that held the lease was merged into CNX Gas Company as part of an internal reorganization. Rowland alleges that (i) Dominion Resources' sale ofthe subsidiary to CONSOL Energy was a change in control that required its consent under the terms of the farmout agreement and lease, and/or (ii) thesubsequent merger of the subsidiary into CNX Gas Company was an assignment that required its consent under the lease. Rowland has recently beenpermitted to file its Third Amended Complaint to include additional allegations that CONSOL Energy has slandered Rowland's title. A motion to dismiss willbe filed. Initial mediation efforts have been unsuccessful. 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.At December 31, 2013, 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. CONSOL Energy managementbelieves that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.153 Amount of Commitment Expiration Per Period TotalAmountsCommitted Less Than1 Year 1-3 Years 3-5 Years Beyond5 YearsLetters of Credit: Employee-Related$190,358 $164,852 $25,506 $— $—Environmental56,293 23,075 33,218 — —Other114,106 76,460 37,646 — —Total Letters of Credit360,757 264,387 96,370 — —Surety Bonds: Employee-Related204,884 204,884 — — —Environmental610,209 610,209 — — —Other32,492 32,481 10 — 1Total Surety Bonds847,585 847,574 10 — 1Gurantees: Coal333,460 200,400 133,060 — —Other70,523 35,611 10,846 9,718 14,348Total Guarantees403,983 236,011 143,906 9,718 14,348Total Commitments$1,612,325 $1,347,972 $240,286 $9,718 $14,349Included in the above table are commitments and guarantees entered into in conjunction with the sale of Consolidation Coal Company (CCC) andcertain of its subsidiaries, which contain all five of its longwall coal mines in West Virginia, and its river operations to a subsidiary of Murray EnergyCorporation (Murray Energy), CONSOL Energy has guaranteed certain equipment lease obligations and coal sales agreement that are being assumed byMurray Energy. In the event that Murray Energy would default on the obligations defined in the agreements, CONSOL Energy would be required to performunder the guarantees. If CONSOL Energy would be required to perform, the stock purchase agreement provides various recourse actions, such as certainMurray Energy collateral and/or Murray Energy indemnifications. At December 31, 2013, the fair value of these guarantees was $3,000 and are included inOther Accrued Liabilities on the Consolidated Balance Sheet. The fair value of certain of the guarantees was determined using CONSOL Energy’s riskadjusted interest rate. Significant increases or decreases in the risk-adjusted interest rates may result in a significantly higher or lower fair value measurement.Coal sales agreement guarantees were valued based on an evaluation of coal market pricing compared to contracted sales price and includes an adjustment fornonperformance risk. No other amounts related to financial guarantees and letters of cried are recorded as liabilities in the financial statements. Significantjudgment is required in determining the fair value of these guarantees. The guarantees of the leases and sales agreements are classified within Level 3 of the fairvalue hierarchy.CONSOL Energy regularly evaluates the likelihood of default for all guarantees based on an expected loss analysis and records the fair value, if any,of its guarantees as an obligation in the consolidated financial statements. 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, 2013, the purchase obligations for each of the next five years and beyond were as follows: Obligations DueAmountLess than 1 year$240,8701 - 3 years260,2183 - 5 years199,144More than 5 years583,333Total Purchase Obligations$1,283,565154Costs related to these purchase obligations include: For The Years Ended December 31, 2013 2012 2011Gas drilling obligations$109,609 $110,975 $108,167Firm transportation expense126,766 78,475 59,606Major equipment purchases12,668 101,367 34,219Other— 492 891Total costs related to purchase obligations$249,043 $291,309 $202,883NOTE 25—SEGMENT INFORMATION:CONSOL Energy has two principal business divisions: Gas and Coal. The principal activity of the Gas division is to produce pipeline quality naturalgas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Marcellus, Coalbed Methane,Shallow Oil and Gas and Other Gas. The Other Gas segment includes our purchased gas activities, general and administrative activities as well as variousother activities assigned to the Gas division but not allocated to each individual well type. The principal activities of the Coal division are mining, preparationand marketing 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 twelve months ended December 31, 2013, the Thermal aggregatedsegment includes the following mines: Bailey, Enlow Fork, Fola Complex, and Miller Creek Complex. For the twelve months ended December 31, 2013, theLow Volatile Metallurgical aggregated segment includes the Buchanan Mine and Amonate Complex. For the twelve months ended December 31, 2013, the HighVolatile Metallurgical aggregated segment includes: Bailey, Enlow Fork, and Fola Complex coal sales. The Other Coal segment includes our purchased coalactivities, idled mine activities, general and administrative activities as well as various other activities assigned to the Coal division but not allocated to eachindividual mine. CONSOL Energy’s All Other segment includes industrial supplies, coal terminal operations and various other corporate activities that are notallocated to the gas or coal segment. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based onsales less identifiable operating and non-operating expenses. Assets are reflected at the division level only (coal, gas and other) and are not allocated betweeneach individual segment. This presentation is consistent with the information regularly reviewed by the chief operating decision maker. The assets are notallocated to each individual segment due to the diverse asset base controlled by CONSOL Energy where each individual asset may service more than onesegment within the division. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.155Industry segment results for the year ended December 31, 2013 are: MarcellusShale CoalbedMethane Shallow Oiland Gas OtherGas TotalGas Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$251,846 $335,730 $131,135 $18,990 $737,701 $1,388,005 $447,417 $159,888 $22,757 $2,018,067 $259,783 $— $3,015,551(A)Sales—purchased gas— — — 6,531 6,531 — — — — — — — 6,531 Sales—gas royalty interests— — — 63,202 63,202 — — — — — — — 63,202 Freight—outside— — — — — — — — 35,438 35,438 — — 35,438 Intersegment transfers— — — 3,167 3,167 — — — — — 127,553 (130,720) — Total Sales and Freight$251,846 $335,730 $131,135 $91,890 $810,601 $1,388,005 $447,417 $159,888 $58,195 $2,053,505 $387,336 $(130,720) $3,120,722 Earnings (Loss) Before IncomeTaxes$79,439 $81,392 $(17,829) $(144,616) $(1,614) $375,787 $121,285 $40,500 $(201,048) $336,524 $(47,468) $(241,367) $46,075(B)Segment assets $6,334,468 $4,187,285 $293,486 $578,428 $11,393,667(C)Depreciation, depletion andamortization $229,562 $218,414 $13,146 $— $461,122 Capital expenditures $968,607 $458,653 $68,796 $— $1,496,056 (A)Included in the Coal segment are sales of $495,242 to Xcoal Energy & Resources and $346,424 to Duke Energy each comprising over 10% of sales.(B)Includes equity in earnings of unconsolidated affiliates of $17,346, $14,684 and $1,102 for Coal, Gas and All Other, respectively.(C)Includes investments in unconsolidated equity affiliates of $20,512, $206,060 and $65,103 for Coal, Gas and All Other, respectively.156Industry segment results for the year ended December 31, 2012 are: MarcellusShale CoalbedMethane Shallow Oiland Gas OtherGas TotalGas Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$134,080 $379,595 $135,412 $9,733 $658,820 $1,430,912 $505,670 $210,153 $22,890 $2,169,625 $294,105 $— $3,122,550(D)Sales—purchased gas— — — 3,316 3,316 — — — — — — — 3,316 Sales—gas royalty interests— — — 49,405 49,405 — — — — — — — 49,405 Freight—outside— — — — — — — — 107,079 107,079 — — 107,079 Intersegment transfers— — — 1,622 1,622 — — — — — 142,014 (143,636) — Total Sales and Freight$134,080 $379,595 $135,412 $64,076 $713,163 $1,430,912 $505,670 $210,153 $129,969 $2,276,704 $436,119 $(143,636) $3,282,350 Earnings (Loss) BeforeIncome Taxes$29,546 $125,970 $(13,390) $(102,675) $39,451 $396,748 $210,133 $57,163 $(72,417) $591,627 $10,997 $(235,388) $406,687(E)Segment assets $5,768,882 $4,104,981 $363,676 $2,760,055 $12,997,594(F)Depreciation, depletionand amortization $202,956 $211,831 $12,328 $— $427,115 Capital expenditures $532,636 $662,888 $49,973 $— $1,245,497 (D)Included in the Coal segment are sales of $382,843 to Xcoal Energy & Resources comprising over 10% of sales.(E)Includes equity in earnings of unconsolidated affiliates of $17,318, $9,562 and $168 for Coal, Gas and All Other, respectively.(F)Includes investments in unconsolidated equity affiliates of $19,517, $143,876 and $59,437 for Coal, Gas and All Other, respectively.157Industry segment results for the year ended December 31, 2011 are: MarcellusShale CoalbedMethane Shallow Oiland Gas OtherGas TotalGas Thermal Low VolatileMetallurgical High VolatileMetallurgical OtherCoal Total Coal AllOther Corporate,Adjustments&Eliminations Consolidated Sales—outside$118,973 $462,677 $155,444 $11,370 $748,464 $1,495,480 $1,071,570 $324,377 $66,333 $2,957,760 $284,783 $— $3,991,007(G)Sales—purchasedgas— — — 4,344 4,344 — — — — — — — 4,344 Sales—gasroyaltyinterests— — — 66,929 66,929 — — — — — — — 66,929 Freight—outside— — — — — — — — 175,633 175,633 — — 175,633 Intersegmenttransfers— — — 3,303 3,303 — — — — — 194,857 (198,160) — TotalSales andFreight$118,973 $462,677 $155,444 $85,946 $823,040 $1,495,480 $1,071,570 $324,377 $241,966 $3,133,393 $479,640 $(198,160) $4,237,913 Earnings (Loss)BeforeIncomeTaxes$41,566 $185,761 $(14,732) $(82,811) $129,784 $421,683 $692,249 $129,119 $(210,354) $1,032,697 $3,408 $(292,963) $872,926(H)Depreciation,depletionandamortization $206,821 $214,285 $9,471 $— $430,577 Capitalexpenditures $664,612 $472,591 $41,172 $— $1,178,375 (G) Included in the Coal segment are sales of $655,596 to Xcoal Energy & Resources comprising over 10% of sales.(H) Includes equity in earnings of unconsolidated affiliates of $19,629, $4,231 and $803 for Coal, Gas and All Other, respectively. 158Reconciliation of Segment Information to Consolidated Amounts:Revenue and Other Income: For the Years Ended December 31, 2013 2012 2011Total segment sales and freight from external customers $3,120,722 $3,282,350 $4,237,913Other income not allocated to segments (Note 4) 178,963 395,176 139,132Total Consolidated Revenue and Other Income $3,299,685 $3,677,526 $4,377,045Earnings Before Income Taxes: For the Years Ended December 31, 2013 2012 2011Segment Earnings Before Income Taxes for total reportable business segments $334,910 $631,078 $1,162,481Segment Earnings Before Income Taxes for all other businesses (47,468) 10,997 3,408Interest income (expense), net and other non-operating activity (I) (226,199) (228,804) (258,308)Transaction and Financing Fees (I) — — (14,907)Evaluation fees for non-core asset dispositions (I) (15,168) (6,584) (5,780)Loss on debt extinguishment — — (16,090)Lease Settlement — — 2,122Earnings Before Income Taxes $46,075 $406,687 $872,926 Total Assets: December 31, 2013 2012Segment assets for total reportable business segments $10,521,753 $9,873,863Segment assets for all other businesses 293,486 363,676Items excluded from segment assets: Cash and other investments (I) 321,992 19,252Recoverable income taxes 10,705 —Deferred tax assets 211,303 84,777Bond issuance costs 34,428 41,775Discontinued Operations — 2,614,251Total Consolidated Assets $11,393,667 $12,997,594_________________________ (I) Excludes amounts specifically related to the gas segment.159Enterprise-Wide Disclosures:CONSOL Energy's Revenues by geographical location (J): For the Years Ended December 31, 2013 2012 2011United States (K) $2,999,674 $2,898,341 $3,460,871Europe 83,878 187,313 366,384South America 29,787 169,591 400,307Canada 3,575 5,692 10,351Other 3,808 21,413 —Total Revenues and Freight from External Customers (K) $3,120,722 $3,282,350 $4,237,913_________________________(J) CONSOL Energy attributes revenue to individual countries based on the location of the customer.(K) 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, 2013 2012United States $9,431,238 $8,487,614Canada 11,024 20,444Discontinued Operations — 1,682,909Total Property, Plant and Equipment, net $9,442,262 $10,190,967NOTE 26—GUARANTOR SUBSIDIARIES FINANCIAL INFORMATION:The payment obligations under the $1,500,000, 8.000% per annum senior notes due April 1, 2017, the $1,250,000, 8.250% per annum senior notesdue April 1, 2020, and the $250,000, 6.375% per annum senior notes due March 1, 2021 issued by CONSOL Energy are jointly and severally, and alsofully and unconditionally guaranteed by substantially all subsidiaries of CONSOL Energy. In accordance with positions established by the Securities andExchange Commission (SEC), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, a guarantorsubsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. The principal elimination entries include investments in subsidiaries andcertain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all otherwholly owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities arereflected as parent company or guarantor company amounts for purposes of this presentation.160Income Statement for the Year Ended December 31, 2013: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $740,869 $2,061,652 $216,419 $(3,389) $3,015,551Sales—Gas Royalty Interests— 63,202 — — — 63,202Sales—Purchased Gas— 6,531 — — — 6,531Freight—Outside— — 35,438 — — 35,438Other Income930,481 57,592 100,757 20,614 (930,481) 178,963Total Revenue and OtherIncome930,481 868,194 2,197,847 237,033 (933,870) 3,299,685Cost of Goods Sold and OtherOperating Charges (exclusive ofdepreciation, depletion andamortization shown below)170,702 493,416 1,313,601 219,450 31,783 2,228,952Gas Royalty Interests Costs— 53,069 — — (41) 53,028Purchased Gas Costs— 4,837 — — — 4,837Related Party Activity35,678 — (112,626) 1,767 75,181 —Freight Expense— — 35,438 — — 35,438Selling, General and AdministrativeExpenses— 44,733 44,357 1,318 — 90,408Depreciation, Depletion andAmortization12,857 229,562 216,726 1,977 — 461,122Interest Expense211,449 8,605 (423) 47 (480) 219,198Taxes Other Than Income3,669 35,176 118,675 3,107 — 160,627Total Costs434,355 869,398 1,615,748 227,666 106,443 3,253,610Earnings (Loss) Before IncomeTaxes496,126 (1,204) 582,099 9,367 (1,040,313) 46,075Income Tax (Benefit) Expense(164,316) 1,420 126,164 3,543 — (33,189)Income (Loss) from ContinuingOperations660,442 (2,624) 455,935 5,824 (1,040,313) 79,264Income from DiscontinuedOperations, net of tax— — — 579,792 — 579,792Net Income (Loss)660,442 (2,624) 455,935 585,616 (1,040,313) 659,056 Less: Net Loss Attributable toNoncontrolling Interest— 1,386 — — — 1,386Net Income (Loss) Attributable toCONSOL Energy Inc.Shareholders$660,442 $(1,238) $455,935 $585,616 $(1,040,313) $660,442161Balance Sheet for December 31, 2013: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedAssets: Current Assets: Cash and Cash Equivalents$320,473 $6,238 $— $709 $— $327,420Accounts and Notes Receivable: Trade— 71,911 — 260,663 — 332,574Notes Receivable1,238 — 24,623 — — 25,861Other Receivables17,657 207,128 14,969 4,219 — 243,973Inventories— 15,185 99,320 43,409 — 157,914Deferred Income Taxes219,566 (8,263) — — — 211,303Recoverable Income Taxes(16,262) 26,967 — — — 10,705Prepaid Expenses43,698 65,701 24,915 1,528 — 135,842Total Current Assets586,370 384,867 163,827 310,528 — 1,445,592Property, Plant and Equipment: Property, Plant and Equipment220,355 6,919,972 6,412,378 25,804 — 13,578,509Less-Accumulated Depreciation, Depletion andAmortization145,754 1,188,464 2,783,043 18,986 — 4,136,247Total Property, Plant and Equipment-Net74,601 5,731,508 3,629,335 6,818 — 9,442,262Other Assets: Investment in Affiliates11,965,054 206,060 70,222 — (11,949,661) 291,675Notes Receivable125 — — — — 125Other145,401 30,728 28,831 9,053 — 214,013Total Other Assets12,110,580 236,788 99,053 9,053 (11,949,661) 505,813Total Assets$12,771,551 $6,353,163 $3,892,215 $326,399 $(11,949,661) $11,393,667Liabilities and Equity: Current Liabilities: Accounts Payable$180,261 $324,226 $493 $9,600 $— $514,580Accounts Payable (Recoverable)—Related Parties4,563,327 23,287 (5,055,923) 136,822 332,487 —Current Portion Long-Term Debt1,029 6,258 3,372 796 — 11,455Short-Term Notes Payable— 332,487 — — (332,487) —Other Accrued Liabilities144,612 89,080 322,606 9,399 — 565,697Current Liabilities of Discontinued Operations— — — 28,239 — 28,239Total Current Liabilities4,889,229 775,338 (4,729,452) 184,856 — 1,119,971Long-Term Debt: Long-Term Debt3,004,213 — 111,750 — — 3,115,963Capital Lease Obligations1,245 42,852 1,724 1,775 — 47,596Total Long-Term Debt3,005,458 42,852 113,474 1,775 — 3,163,559Deferred Credits and Other Liabilities Deferred Income Taxes(232,904) 475,547 — — — 242,643Postretirement Benefits Other Than Pensions— — 961,127 — — 961,127Pneumoconiosis Benefits— — 111,971 — — 111,971Mine Closing— — 320,723 — — 320,723Gas Well Closing— 119,429 56,174 — — 175,603Workers’ Compensation— — 71,136 332 — 71,468Salary Retirement48,252 — — — — 48,252Reclamation— — 40,706 — — 40,706Other55,227 61,190 14,938 — — 131,355Total Deferred Credits and Other Liabilities(129,425) 656,166 1,576,775 332 — 2,103,848Total CONSOL Energy Inc. Stockholders’ Equity5,006,289 4,878,807 6,931,418 139,436 (11,949,661) 5,006,289Total Liabilities and Equity$12,771,551 $6,353,163 $3,892,215 $326,399 $(11,949,661) $11,393,667162Condensed Statement of Cash Flows For the Year Ended December 31, 2013: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by (Used in) Continuing Operations$51,093 $440,763 $572,683 $(843,456) $332,487 $553,570Net Cash Provided by Discontinued Operating Activities— — — 105,206 — 105,206Net Cash Provided by (Used in) Operating Activities$51,093 $440,763 $572,683 $(738,250) $332,487 $658,776Cash Flows from Investing Activities: Capital Expenditures$(68,796) $(968,607) $(458,653) $— $— $(1,496,056)Change in Restricted Cash— — 68,673 — — 68,673Proceeds From Sales of Assets327,964 350,975 (195,082) 112 — 483,969(Investments in), net of Distributions from, EquityAffiliates— (47,500) 11,788 — — (35,712)Net Cash (Used in) Provided by ContinuingOperations259,168 (665,132) (573,274) 112 — (979,126)Net Cash Provided by Discontinued InvestingActivities— — — 777,145 — 777,145Net Cash (Used in) Provided by InvestingActivities$259,168 $(665,132) $(573,274) $777,257 $— $(201,981)Cash Flows from Financing Activities: Dividends (Paid)$14,168 $(100,000) $— $— $— $(85,832)Payments on Short-Term Borrowings— 332,487 — — (332,487) —Payments on Miscellaneous Borrowings(25,952) — (4,800) (792) — (31,544)Proceeds from Securitization Facility— — — (37,846) — (37,846)Proceeds from Issuance of Common Stock3,727 — — — — 3,727Other Financing Activities778 (5,232) 5,232 — — 778Net Cash (Used in) Provided by ContinuingOperations(7,279) 227,255 432 (38,638) (332,487) (150,717)Net Cash Used in Discontinued FinancingActivities— — — (520) — (520)Net Cash (Used in) Provided by FinancingActivities$(7,279) $227,255 $432 $(39,158) $(332,487) $(151,237)163Income Statement for the Year Ended December 31, 2012: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $660,442 $2,221,421 $243,059 $(2,372) $3,122,550Sales—Gas Royalty Interests— 49,405 — — — 49,405Sales—Purchased Gas— 3,316 — — — 3,316Freight—Outside— — 107,079 — — 107,079Other Income613,340 56,946 316,592 21,639 (613,341) 395,176Total Revenue and OtherIncome613,340 770,109 2,645,092 264,698 (615,713) 3,677,526Cost of Goods Sold and OtherOperating Charges (exclusive ofdepreciation, depletion andamortization shown below)127,372 407,045 1,417,519 239,502 30,421 2,221,859Gas Royalty Interests Costs— 38,922 — — (55) 38,867Purchased Gas Costs— 2,711 — — — 2,711Related Party Activity12,865 — (22,466) 1,814 7,787 —Freight Expense— — 107,079 — — 107,079Selling, General and AdministrativeExpenses— 40,101 49,222 1,417 — 90,740Depreciation, Depletion andAmortization12,172 202,956 209,923 2,064 — 427,115Interest Expense208,894 5,098 6,470 44 (464) 220,042Taxes Other Than Income401 33,892 125,288 2,845 — 162,426Total Costs361,704 730,725 1,893,035 247,686 37,689 3,270,839Earnings (Loss) Before IncomeTaxes251,636 39,384 752,057 17,012 (653,402) 406,687Income Tax Expense (Benefit)(136,834) 15,021 204,105 6,436 — 88,728Income (Loss) from ContinuingOperations388,470 24,363 547,952 10,576 (653,402) 317,959Income from DiscontinuedOperations, net of tax— — — 70,114 — 70,114Net Income (Loss)388,470 24,363 547,952 80,690 (653,402) 388,073 Less: Net Loss Attributable toNoncontrolling Interest— 397 — — — 397Net Income (Loss) Attributable toCONSOL Energy Inc.Shareholders$388,470 $24,760 $547,952 $80,690 $(653,402) $388,470164Balance Sheet for December 31, 2012: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedAssets: Current Assets: Cash and Cash Equivalents$17,491 $3,352 $159 $860 $— $21,862Accounts and Notes Receivable: Trade— 58,126 — 370,202 — 428,328Securitized— — — 37,846 — 37,846Notes Receivable154 315,730 2,503 — — 318,387Other Receivables6,335 214,748 33,289 5,159 (128,400) 131,131Inventories— 14,133 121,311 35,364 — 170,808Deferred Income Taxes174,176 (26,072) (63,327) — — 84,777Restricted Cash— — 48,294 — — 48,294Prepaid Expenses29,589 86,186 31,286 1,370 — 148,431Current Assets of Discontinued Operations— — — 149,230 — 149,230Total Current Assets227,745 666,203 173,515 600,031 (128,400) 1,539,094Property, Plant and Equipment: Property, Plant and Equipment216,448 5,956,207 5,923,723 25,179 — 12,121,557Less-Accumulated Depreciation, Depletion andAmortization126,048 960,613 2,508,769 18,069 — 3,613,499Property, Plant and Equipment of DiscontinuedOperations, net— — — 1,682,909 — 1,682,909Total Property, Plant and Equipment-Net90,400 4,995,594 3,414,954 1,690,019 — 10,190,967Other Assets: Restricted Cash— — 20,379 — — 20,379Investment in Affiliates9,917,050 143,876 769,058 — (10,607,154) 222,830Notes Receivable239 — 25,738 — — 25,977Other118,938 65,935 21,174 10,188 — 216,235Other Assets of Discontinued Operations— — — 782,112 — 782,112Total Other Assets10,036,227 209,811 836,349 792,300 (10,607,154) 1,267,533Total Assets$10,354,372 $5,871,608 $4,424,818 $3,082,350 $(10,735,554) $12,997,594165Balance Sheet for December 31, 2012 (Continued): ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedLiabilities and Equity: Current Liabilities: Accounts Payable$177,734 $166,182 $145,469 $9,130 $— $498,515Accounts Payable (Recoverable)-Related Parties3,599,216 23,981 (3,749,584) 254,787 (128,400) —Short-Term Notes Payable25,073 — — — — 25,073Current Portion of Long-Term Debt1,554 5,953 4,221 756 — 12,484Accrued Income Taxes20,488 13,731 — — — 34,219Borrowings under Securitization Facility— — — 37,846 — 37,846Other Accrued Liabilities135,407 57,074 343,739 9,528 — 545,748Current Liabilities of Discontinued Operations— — — 233,214 — 233,214Total Current Liabilities3,959,472 266,921 (3,256,155) 545,261 (128,400) 1,387,099Long-Term Debt: Long-Term Debt3,004,798 — 118,802 — — 3,123,600Capital Lease Obligations717 46,081 1,148 1,467 — 49,413Long-Term Debt of Discontinued Operations— — — 1,573 — 1,573Total Long-Term Debt3,005,515 46,081 119,950 3,040 — 3,174,586Deferred Credits and Other Liabilities: Deferred Income Taxes(884,310) 439,725 771,270 — — 326,685Postretirement Benefits Other Than Pensions— — 882,600 — — 882,600Pneumoconiosis Benefits— — 114,136 — — 114,136Mine Closing— — 289,818 — — 289,818Gas Well Closing— 80,097 65,905 — — 146,002Workers’ Compensation— — 60,090 306 — 60,396Salary Retirement218,004 — — — — 218,004Reclamation— — 47,965 — — 47,965Other101,899 24,518 (8,110) — — 118,307Deferred Credits and Other Liabilities ofDiscontinued Operations— — — 2,278,251 — 2,278,251Total Deferred Credits and Other Liabilities(564,407) 544,340 2,223,674 2,278,557 — 4,482,164Total CONSOL Energy Inc. Stockholders’ Equity3,953,792 5,014,313 5,337,349 255,492 (10,607,154) 3,953,792Noncontrolling Interest— (47) — — — (47)Total Liabilities and Equity$10,354,372 $5,871,608 $4,424,818 $3,082,350 $(10,735,554) $12,997,594166Condensed Statement of Cash Flows For the Year Ended December 31, 2012: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by (Used in) Continuing Operations$(58,410) $82,036 $412,293 $21,423 $— $457,342Net Cash Provided by Discontinued Operating Activities— — — 270,771 — 270,771Net Cash Provided by (Used in) Operating Activities$(58,410) $82,036 $412,293 $292,194 $— $728,113Cash Flows from Investing Activities: Capital Expenditures$(49,973) $(532,636) $(662,888) $— $— $(1,245,497)Change in Restricted Cash— — (48,294) — — (48,294)Proceeds From Sales of Assets— 360,129 285,238 254 — 645,621(Investments in), net of Distributions from, EquityAffiliates200,000 (37,400) 13,949 — (200,000) (23,451)Net Cash (Used in) Provided by ContinuningOperations$150,027 $(209,907) $(411,995) $254 $(200,000) $(671,621)Net Cash Used in Discontinued InvestingActivities— — — (328,789) — (328,789)Net Cash (Used in) Provided by InvestingActivities$150,027 $(209,907) $(411,995) $(328,535) $(200,000) $(1,000,410)Cash Flows from Financing Activities: Dividends (Paid)$(142,278) $(200,000) $— $— $200,000 $(142,278)Proceeds from Issuance of Common Stock8,278 — — — — 8,278Other Financing Activities22,532 (5,504) (1,408) 37,404 — 53,024Net Cash (Used in) Provided by ContinuingOperations$(111,468) $(205,504) $(1,408) $37,404 $200,000 $(80,976)Net Cash Used in Discontinued FinancingActivities— — — (601) — (601)Net Cash (Used in) Provided by FinancingActivities$(111,468) $(205,504) $(1,408) $36,803 $200,000 $(81,577)167Income Statement for the Year Ended December 31, 2011: ParentIssuer CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedSales—Outside$— $751,767 $3,009,104 $234,998 $(4,862) $3,991,007Sales—Gas Royalty Interests— 66,929 — — — 66,929Sales—Purchased Gas$— $4,344 $— $— $— $4,344Freight—Outside— — 175,633 — — 175,633Other Income876,233 58,923 48,673 26,309 (871,006) 139,132Total Revenue and Other Income876,233 881,963 3,233,410 261,307 (875,868) 4,377,045Cost of Goods Sold and Other OperatingCharges (exclusive of depreciation,depletion, and amortization shownbelow)108,681 388,507 1,443,472 228,291 97,609 2,266,560Gas 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— — 175,444 — — 175,444Selling, General and AdministrativeExpenses— 50,429 62,729 1,485 — 114,643Depreciation, Depletion andAmortization12,194 206,821 209,159 2,403 — 430,577Interest Expense235,370 9,398 3,911 53 (388) 248,344Taxes Other Than Income950 34,023 136,382 3,037 — 174,392Transaction and FinancingFees14,907 — — — — 14,907Loss on Debt Extinguishment16,090 — — — — 16,090Total Costs392,959 752,386 2,005,377 237,255 116,142 3,504,119Earnings (Loss) Before Income Taxes483,274 129,577 1,228,033 24,052 (992,010) 872,926Income Tax Expense (Benefit)(149,223) 51,876 279,500 9,098 — 191,251Income (Loss) from ContinuingOperations632,497 77,701 948,533 14,954 (992,010) 681,675Loss from Discontinued Operations, netof tax— — — (49,178) — (49,178)Net Income (Loss) Attributable toCONSOL Energy Inc. Shareholders$632,497 $77,701 $948,533 $(34,224) $(992,010) $632,497168Condensed Statement of Cash Flows For the Year Ended December 31, 2011: Parent CNX GasGuarantor Other SubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Cash Provided by (Used in) ContinuingOperations$530,444 $329,360 $465,847 $3,220 $— $1,328,871Net Cash Provided by Discontinued OperatingActivities$— $— $— $198,735 $— 198,735Net Cash Provided by (Used in) Operating Activities$530,444 $329,360 $465,847 $201,955 $— $1,527,606Cash Flows from Investing Activities: Capital Expenditures$(41,172) $(664,612) $(472,591) $— $— $(1,178,375)Proceeds From Sales of Assets10 746,956 (1,155) 1,474 — 747,285Distributions from, net of Investments in,Equity Affiliates— 50,626 5,250 — — 55,876Net Cash (Used in) Provided byContinuing Operations$(41,162) $132,970 $(468,496) $1,474 $— $(375,214)Net Cash Used in Discontinued InvestingActivities— — — (203,310) — (203,310)Net Cash (Used in) Provided by InvestingActivities$(41,162) $132,970 $(468,496) $(201,836) $— $(578,524)Cash Flows from Financing Activities: Dividends Paid$(96,356) $— $— $— $— $(96,356)Payments on Short-Term Borrowings(155,000) (129,000) — — — (284,000)Payments on Securitization Facility(200,000) — — — — (200,000)Proceeds from Long-Term Notes250,000 — — — — 250,000Payments on Long Term Notes, includingRedemption Premium(265,785) — — — — (265,785)Other Financing Activities5,749 (13,162) (1,246) (793) — (9,452)Net Cash Used in Continuing Operations$(461,392) $(142,162) $(1,246) $(793) $— $(605,593)Net Cash Used in Discontinued FinancingActivities— — — (547) — (547)Net Cash Used in Financing Activities$(461,392) $(142,162) $(1,246) $(1,340) $— $(606,140)Statement of Comprehensive Income for the Year Ended December 31, 2013: Parent CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Income (Loss)$660,442 $(2,624) $455,935 $585,616 $(1,040,313) $659,056Other Comprehensive Income (Loss): Actuarially Determined Long-Term Liability Adjustments456,493 — 456,493 — (456,493) 456,493 Net Increase (Decrease) in the Value of Cash Flow Hedge45,631 45,631 — — (45,631) 45,631 Reclassification of Cash Flow Hedge from OCI to Earnings(79,899) (79,899) — — 79,899 (79,899)Other Comprehensive Income (Loss):$422,225 $(34,268) $456,493 $— $(422,225) $422,225Comprehensive Income (Loss)1,082,667 (36,892) 912,428 585,616 (1,462,538) 1,081,281 Less: Comprehensive Loss Attributable to NoncontrollingInterest— 1,386 — — — 1,386Comprehensive Income (Loss) Attributable to CONSOLEnergy Inc. Shareholders$1,082,667 $(35,506) $912,428 $585,616 $(1,462,538) $1,082,667169Statement of Comprehensive Income for the Year Ended December 31, 2012: Parent CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Income (Loss)$388,470 $24,363 $547,952 $80,690 $(653,402) $388,073Other Comprehensive Income (Loss): Actuarially Determined Long-Term Liability Adjustments129,231 — 129,231 — (129,231) 129,231 Net Increase (Decrease) in the Value of Cash Flow Hedge114,240 114,240 — — (114,240) 114,240 Reclassification of Cash Flow Hedge from OCI toEarnings(189,259) (189,259) — — 189,259 (189,259)Other Comprehensive Income (Loss):$54,212 $(75,019) $129,231 $— $(54,212) $54,212Comprehensive Income (Loss)$442,682 $(50,656) $677,183 $80,690 $(707,614) $442,285 Less: Comprehensive Income Attributable to NoncontrollingInterest— 397 — — — 397Comprehensive Income (Loss) Attributable to CONSOLEnergy Inc. Shareholders$442,682 $(50,259) $677,183 $80,690 $(707,614) $442,682Statement of Comprehensive Income for the Year Ended December 31, 2011: Parent CNX GasGuarantor OtherSubsidiaryGuarantors Non-Guarantors Elimination ConsolidatedNet Income (Loss)$632,497 $77,701 $948,533 $(34,224) $(992,010) $632,497Other Comprehensive Income (Loss): Treasury Rate Lock(96) — — — — (96) Actuarially Determined Long-Term Liability Adjustments(32,813) — (32,813) — 32,813 (32,813) Net Increase (Decrease) in the Value of Cash Flow Hedge200,700 200,700 — — (200,700) 200,700 Reclassification of Cash Flow Hedge from OCI to Earnings(95,007) (95,007) — — 95,007 (95,007)Other Comprehensive Income (Loss):$72,784 $105,693 $(32,813) $— $(72,880) $72,784Comprehensive Income (Loss) Attributable to CONSOLEnergy Inc. Shareholders$705,281 $183,394 $915,720 $(34,224) $(1,064,890) $705,281NOTE 27—RELATED PARTY TRANSACTIONSCONE Gathering LLC Related Party TransactionsDuring the years ended December 31, 2013, 2012 and 2011, CONE Gathering LLC (CONE) a 50% owned affiliate, provided CNX Gas CompanyLLC (CNX Gas Company) gathering services in the ordinary course of business. Gathering services received from CONE were $34,062, $20,408 and$4,267 in the years ended December 31, 2013, 2012 and 2011 respectively, which were included in Cost of Goods Sold on the Consolidated Statements ofIncome.As of December 31, 2013 and 2012, CONSOL Energy and CNX Gas had a net payable of $5,448 and $3,142, respectively, due to CONE which iscomprised of the following items:170 December 31, December 31, 2013 2012 Location on Balance SheetReimbursement for CONE Expenses$(2,168) $(1,336) Accounts Receivable–OtherReimbursement for Services Provided to CONE(265) (341) Accounts Receivable–OtherCONE Gathering Capital Reimbursement— (18) Accounts Receivable–OtherCONE Gathering Fee Payable7,881 4,837 Accounts PayableNet Payable due CONE$5,448 $3,142 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, 2013 2012Proven properties $1,670,404 $1,596,838Unproven properties 1,463,406 1,266,017Intangible drilling costs 1,937,336 1,550,297Wells and related equipment 688,548 492,364Gathering assets 1,058,008 1,006,882Gas Well Plugging 113,481 70,753Total Property, Plant and Equipment 6,931,183 5,983,151Accumulated Depreciation, Depletion and Amortization (1,187,409) (959,291)Net Capitalized Costs $5,743,774 $5,023,860Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2013 2012 2011Property acquisitions Proven properties $— $50,005 $6,673Unproven properties 260,477 28,634 58,731Development 629,100 339,608 463,401Exploration 95,413 130,312 131,419Total $984,990 $548,559 $660,224__________(*)Includes costs incurred whether capitalized or expensed.171Results of Operations for Producing Activities: For the Years Ended December 31, 2013 2012 2011Production Revenue $740,869 $660,442 $751,767Royalty Interest Gas Revenue 63,202 49,405 66,929Purchased Gas Revenue 6,531 3,316 4,344Total Revenue 810,602 713,163 823,040Lifting Costs 96,600 90,835 106,477Ad Valorem, Severance & Other Taxes 28,677 26,145 26,261Gathering Costs 201,023 160,575 142,339Royalty Interest Gas Costs 53,069 38,922 59,377Direct Administrative, Selling & Other Costs 49,092 47,567 60,355Other Costs 61,119 39,029 18,095Purchased Gas Costs 4,837 2,711 3,831DD&A 229,562 202,956 206,821Total Costs 723,979 608,740 623,556Pre-tax Operating Income 86,623 104,423 199,484Income Taxes 32,917 39,827 79,873Results of Operations for Producing Activities excluding Corporate and InterestCosts $53,706 $64,596 $119,611The 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, 2013 2012 2011Production (MMcfe) 172,380 156,325 153,504Average gas sales price before effects of financial settlements (per Mcf) $3.85 $3.00 $4.27Average effects of financial settlements (per Mcf) $0.45 $1.22 $0.63Average gas sales price including effects of financial settlements (per Mcf) $4.30 $4.22 $4.90Average lifting costs, excluding ad valorem and severance taxes (per Mcf) $0.56 $0.58 $0.68During the years ended December 31, 2013, 2012 and 2011, we drilled 139.8, 95.5, and 254.9 net development wells, respectively. There were no netdry development wells in 2013, 2012, or 2011.During the years ended December 31, 2013, 2012 and 2011, we drilled 5.5, 22.0, and 69.5 net exploratory wells, respectively. There were zero net dryexploratory wells in 2013, seven net dry exploratory wells in 2012 and two net dry exploratory wells in 2011.At December 31, 2013, there were 31.0 net development wells in the process of being drilled.At December 31, 2013, there were 1.0 net exploratory wells in the process of being drilled.CONSOL Energy is committed to provide 60.3 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 commitments172or other term commitments are satisfied. The following table sets forth, at December 31, 2013, the number of producing wells, developed acreage andundeveloped acreage: Gross Net(1)Producing Wells (including gob wells) 15,063 12,874Proved Developed Acreage 542,388 527,693Proved Undeveloped Acreage 105,019 59,346Unproved Acreage 5,396,659 4,212,030 Total Acreage 6,044,066 4,799,069____________(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 Reserves Quantities:Annually, the preparation of our gas reserves estimates are completed in accordance with CONSOL Energy's prescribed internal control procedures,which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. Theinput data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumesare reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeingthe preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. Our 2013 gas reserves results,which are reported in the Supplemental Gas Data year ended December 31, 2013 Form 10-K, were audited by Netherland Sewell. The technical personprimarily responsible for overseeing the audit of our reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oiland gas industry. The gas reserves estimates are as follows:173 Condensate Consolidated Natural Gas NGLs & Crude Oil Operations (MMcfe) (Mbbls) (Mbbls) (MMcfe)Balance December 31, 2010 3,724,361 — 1,206 3,731,597Revisions (a) (76,486) 25 416 (73,837)Price Changes (9,976) — — (9,976)Extensions and Discoveries (c) 517,023 — 27 517,178Production (152,940) — (94) (153,504)Sales of Reserves In-Place (531,431) — — (531,431)Balance December 31, 2011 (d) 3,470,551 25 1,555 3,480,027Revisions (b) 243,442 469 (710) 241,989Price Changes (526,608) — (1) (526,611)Extensions and Discoveries (c) 873,104 12,992 553 954,378Production (155,052) (111) (100) (156,325)Sales of Reserves In-Place — — — —Balance December 31, 2012 (d) 3,905,437 13,375 1,297 3,993,458Revisions (b) 176,045 (1,017) 336 171,953Price Changes 104,728 4 1 104,757Extensions and Discoveries (c) 1,567,634 9,623 1,343 1,633,426Production (168,737) (438) (170) (172,380)Sales of Reserves In-Place — — — —Balance December 31, 2013 (d) 5,585,107 21,547 2,807 5,731,214 Proved developed reserves: December 31, 2011 2,126,330 — 1,579 2,135,805December 31, 2012 2,149,912 1,717 878 2,165,483December 31, 2013 2,470,412 5,939 1,375 2,514,294 Proved undeveloped reserves: December 31, 2011 1,344,222 — — 1,344,222December 31, 2012 1,755,525 12,075 — 1,827,975December 31, 2013 3,114,695 15,607 1,431 3,216,920__________(a)Revisions are primarily due corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas andreservoirs. These changes were partially offset by upward revisions attributable to efficiencies in operations and well performance and had the totalaffect of a negative revision for 2011.(b)Revisions are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas andreservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance and had the total affect of thepositive revisions for 2013 and 2012.(c)Extensions and Discoveries are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliabletechnology.(d)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 government regulations. CONSOL Energy cautions that there aremany inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Provedoil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverablein future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves arethose reserves expected to be recovered through existing wells, with existing equipment and operating methods.174 For the Year Ended December 31, 2013Proved Undeveloped Reserves (MMcfe) Beginning proved undeveloped reserves 1,827,975Undeveloped reserves transferred to developed(a) (230,333)Price Changes 11,410Plan and other revisions (b) 88,187Extension and discoveries (c) 1,519,681Ending proved undeveloped reserves(d) 3,216,920_________(a)During 2013, various exploration and development drilling and evaluations were completed. Approximately, $202,066 of capital was spent in the yearended December 31, 2013 related to undeveloped reserves that were transferred to developed.(b) Plan and other revisions are due to corporate planning changes that affect the number of wells forecasted to be drilled in our various areas and reservoirs.These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of a positive revision.(c)Extensions and discoveries include approximately 683 Bcfe which were initially classified as unproved related to the DTI and Airport lease acquisitions. These reserves were subsequently reclassified to proved undeveloped reserves utilizing reliable technologies which include wire line open hole logdata, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from ConsolEnergy's and competitors' wells. Geophysical data include data from Consol's wells, published documents, state data-sites and were used to confirmcontinuity of the formation.(d)Included in proved undeveloped reserves at December 31, 2013 are approximately 226,063 MMcfe of reserves that have been reported for more than fiveyears. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavitycreated by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Miningoperations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also existsthat supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance which resulted from an externalfactor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.The following table represents the capitalized exploratory well cost activity as indicated: December 31, 2013Costs pending the determination of proved reserves at December 31, 2013 For a period one year or less $17,728For a period greater than one year but less than five years —For a period greater than five years — Total $17,728 December 31, 2013 2012 2011Costs reclassified to wells, equipment and facilities based on the determination of provedreserves $12,140 $14,447 $189Costs expensed due to determination of dry hole or abandonment of project $8,596 $3,320 $5,108CONSOL Energy's proved gas reserves are located in the United States.175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, 2013. Because prices used in the calculation are average prices for that year,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, 2013 2012 2011Future Cash Flows: Revenues $21,602,594 $11,777,550 $14,804,398Production costs (7,105,962) (4,823,670) (5,262,635)Development costs (3,902,875) (2,450,589) (1,674,829)Income tax expense (4,025,626) (1,711,251) (2,989,435)Future Net Cash Flows 6,568,131 2,792,040 4,877,499Discounted to present value at a 10% annual rate (4,887,320) (2,055,834) (3,130,318)Total standardized measure of discounted net cash flows $1,680,811 $736,206 $1,747,181The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during: December 31, 2013 2012 2011Balance at beginning of period $736,206 $1,747,181 $1,660,821Net changes in sales prices and production costs 1,295,956 (1,480,573) (339,098)Sales net of production costs (365,477) (104,518) (217,186)Net change due to revisions in quantity estimates 132,900 (104,158) (83,580)Net change due to extensions, discoveries and improved recovery 383,308 14,645 324,755Net change due to (divestiture) acquisition — — (559,132)Development costs incurred during the period 625,824 333,640 463,401Difference in previously estimated development costs compared to actual costs incurredduring the period (123,976) (96,749) 154,137Changes in estimated future development costs (486,518) (153,104) 155,619Net change in future income taxes (578,951) 619,045 130,746Accretion of discount and other 61,539 (39,203) 56,698 Total discounted cash flow at end of period $1,680,811 $736,206 $1,747,181176Supplemental Coal Data (unaudited) Millions of Tons For the Year Ended December 31, 2013 2012 2011 2010 2009Proved and probable reserves at beginning of period 4,229 4,314 4,229 4,350 4,372Purchased reserves 1 — 6 4 5Reserves sold in place (1,199) (155) — (41) (3)Production (55) (55) (62) (62) (58)Revisions and other changes 56 125 141 (22) 34Consolidated proved and probable reserves at end of period* 3,032 4,229 4,314 4,229 4,350 Proportionate share of proved and probable reserves of unconsolidated equity affiliates* 57 41 145 172 170______________* 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. Provedand probable reserves of unconsolidated equity affiliates are included in this number.CONSOL Energy's coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2013, 382 million tonswere assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2013 include2,511 million tons of steam coal reserves, of which approximately 5 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per millionBritish thermal unit (Btu), 18 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu and an additional 77percent has a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million Btu. The reserves also include 521 million tons of metallurgicalcoal in consolidated reserves, of which approximately 49 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu and anadditional 51 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.177Supplemental Quarterly Information (unaudited):(Dollars in thousands, except per share data) Three Months Ended March 31, June 30, September 30, December 31, 2013 2013 2013 2013Sales $799,997 $759,948 $753,080 $772,258Freight Revenue $14,061 $10,125 $11,563 $3,946Cost of Goods Sold and Other Operating Charges (including GasRoyalty Interests' Costs and Purchased Gas Costs) $612,000 $552,126 $560,247 $562,386Freight Expense $14,061 $10,125 $11,563 $3,946(Loss) Income from Continuing Operations $(3,725) $8,562 $(72,169) $146,595Income (Loss) from Discontinued Operations $1,904 $(21,375) $8,120 $591,144Net (Loss) Income Attributable to CONSOL Energy Inc Shareholders $(1,564) $(12,526) $(63,651) $738,183Earnings Per Share Basic: (Loss) Income from Continuing Operations $(0.02) $0.04 $(0.31) $0.64Income (Loss) from Discontinued Operations $0.01 $(0.09) $0.03 $2.58Net (Loss) Income $(0.01) $(0.05) $(0.28) $3.22Dilutive: (Loss) Income from Continuing Operations $(0.02) $0.04 $(0.31) $0.64Income (Loss) from Discontinued Operations $0.01 $(0.09) $0.03 $2.56Net (Loss) Income $(0.01) $(0.05) $(0.28) $3.20 Three Months Ended March 31, June 30, September 30, December 31, 2012 2012 2012 2012Sales $878,118 $807,198 $681,717 $808,238Freight Revenue $49,293 $49,472 $27,430 $13,426Cost of Goods Sold and Other Operating Charges (including GasRoyalty Interests' Costs and Purchased Gas Costs) $601,723 $565,601 $543,158 $557,094Freight Expense $49,293 $49,472 $27,430 $13,426Income (Loss) from Continuing Operations $80,906 $155,789 $(26,316) $107,580Income (Loss) from Discontinued Operations $16,290 $(3,050) $14,814 $42,060Net Income (Loss) Attributable to CONSOL Energy Inc Shareholders $97,196 $152,739 $(11,368) $149,903Earnings Per Share Basic: Income (Loss) from Continuing Operations $0.36 $0.68 $(0.12) $0.47Income (Loss) from Discontinued Operations $0.07 $(0.01) $0.07 $0.19Net Income (Loss) $0.43 $0.67 $(0.05) $0.66Dilutive: Income (Loss) from Continuing Operations $0.35 $0.68 $(0.12) $0.47Income (Loss) from Discontinued Operations $0.07 $(0.01) $0.07 $0.18Net Income (Loss) $0.42 $0.67 $(0.05) $0.65178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, 2013 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, 2013. In making thisassessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (COSO)in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that CONSOL Energy maintained effectiveinternal control over financial reporting as of December 31, 2013.The effectiveness of CONSOL Energy's internal control over financial reporting as of December 31, 2013 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, 2013, based on criteria establishedin Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSOcriteria). CONSOL Energy Inc. and Subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for itsassessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control OverFinancial Reporting appearing under Item 9a. Our responsibility is to express an opinion on the Company's internal control over financial reporting based onour 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, 2013, 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, 2013 and 2012, and the related consolidated statements of income, comprehensiveincome, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2013 of CONSOL Energy Inc. and Subsidiariesand our report dated February 7, 2014 expressed an unqualified opinion thereon./s/ Ernst & Young LLPPittsburgh, PennsylvaniaFebruary 7, 2014180ITEM 9B.OTHER INFORMATIONCONSOL Energy Inc. adopted a recoupment policy that generally provides the Compensation Committee of the Company’s Board of Directors with thediscretion to seek recovery of performance-based cash and equity incentive compensation (the “Awards”) paid to an executive officer in the three years prior toa financial restatement if such executive officer engaged in intentional or unlawful misconduct which materially contributed to the need for such restatementand such Award(s) would have been lower if calculated based on such restated results (the “Clawback Policy”). The Clawback Policy will apply to Awardsgranted in January 2014 and thereafter.PART IIIITEM 10.DIRECTORS, 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 Nominees,” “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 7, 2014 (the“Proxy Statement”).Executive Officers of CONSOL EnergyThe following is a list of CONSOL Energy executive officers, their ages as of February 1, 2014 and their positions and offices held with CONSOLEnergy.Name Age PositionJ. Brett Harvey 63 Chairman of the Board and Chief Executive OfficerNicholas J. DeIuliis 45 PresidentStephen W. Johnson 55 Executive Vice President - Chief Legal and Corporate Affairs OfficerDavid M. Khani 50 Executive Vice President and Chief Financial OfficerJames C. Grech 52 Executive Vice President and Chief Commercial OfficerJ. 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 Energy from January 16, 2009 until February 23, 2011. Prior to that time, Mr. DeIuliis served as Senior Vice President - Strategic Planning ofCONSOL Energy from November 2004 until August 2005, Vice President Strategic Planning from April 2002 until November 2004, Director-CorporateStrategy from October 2001 until April 2002, Manager-Strategic Planning from January 2001 until October 2001 and Supervisor-Process Engineering fromApril 1999 until January 2001. He resigned from his position with CONSOL Energy as of August 8, 2005. He was a Director and President and ChiefExecutive Officer of CNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX GasCorporation, a position which he continues to hold.Stephen W. Johnson became Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporationon January 1, 2013. Prior to that time, Mr. Johnson served as Senior Vice President and General Counsel of CONSOL Energy and CNX Gas Corporationfrom February 5, 2009 through December 31, 2012. Prior to February 5, 2009, he served in the following positions with CNX Gas Corporation: GeneralCounsel from September 1, 2005, Senior Vice President from December 5, 2005 through September 13, 2007 and Executive Vice President from September13, 2007. David M. Khani joined CONSOL Energy on September 1, 2011 as its Vice President - Finance, and was promoted to Executive Vice President andChief Financial Officer effective March 1, 2013. Prior to joining CONSOL Energy, Mr. Khani181was with FBR Capital Markets & Co. ("FBR"), an investment banking and advisory firm and held the following positions: Director of Research fromFebruary 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011.James C. Grech became Chief Commercial Officer on November 15, 2012 and was promoted to Executive Vice President and Chief CommercialOfficer effective March 1, 2013. Mr. Grech had served as Senior Vice President of CNX Land Resources Inc., a subsidiary of CONSOL Energy fromSeptember 13, 2011 until December 5, 2013. He joined the company in 2001 as Vice President of Business Development and was promoted to Senior VicePresident - Marketing of CONSOL Energy Sales Company, another subsidiary of CONSOL Energy, on August 15, 2005. 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 May 31, 2013, 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-2013,” “BOARD OF DIRECTORS AND COMPENSATIONINFORMATION-UNDERSTANDING OUR DIRECTOR COMPENSATION TABLE,” and “EXECUTIVE COMPENSATION INFORMATION” in theProxy 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.2.10 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 16,2010.2.20 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, 2010.2.30 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, 2011.2.40 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, 2011.2.50 Stock Purchase Agreement, dated October 25, 2013, among CONSOL Energy Inc., Consolidation Coal Company, Ohio Valley Resources, Inc.,and, as to certain provisions of the Purchase Agreement, Murray Energy Corporation, incorporated by reference to Exhibit 2.1 to Form 8-K (fileno. 001-14901) filed on December 11, 2013.3.10 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, 2006.3.20 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, 2011.4.10 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, 2010.4.20 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, 2010.4.30 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, 2010.4.40 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, 2011.1834.50 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, 2010.4.60 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, 2010.4.70 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, 2010.4.80 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, 2011.4.90 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, 2011.4.14 Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc.,certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova ScotiaTrust Company of New York, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.1 of Form 10-Q (file no.001-14901) filed on November 1, 2013.4.15 Supplemental Indenture No. 4, dated as of September 10, 2013, to Indenture dated as of April 1, 2010, by and among CONSOL Energy Inc.,certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova ScotiaTrust Company of New York, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 of Form 10-Q (file no.001-14901) filed on November 1, 2013.4.16 Supplemental Indenture No. 2, dated as of September 10, 2013, to Indenture dated as of March 9, 2011, by and among CONSOL Energy Inc.,certain subsidiaries of CONSOL Energy Inc. and Wells Fargo Bank, National Association, as successor trustee to The Bank of Nova ScotiaTrust Company of New York, with respect to the 6.375 % Senior Notes due 2021, incorporated by reference to Exhibit 4.3 of Form 10-Q (fileno. 001-14901) filed on November 1, 2013.4.17 Agreement of Resignation, Appointment and Acceptance, dated July 22, 2013, by and among CONSOL Energy Inc., certain subsidiaries ofCONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor Trustee to The Bank of Nova Scotia TrustCompany of New York, and The Bank of Nova Scotia Trust Company of New York, as Resigning Trustee (related to the Indenture dated as ofApril 1, 2010 with respect to the 8.00% Senior Notes due 2017, the Indenture dated as of April 1, 2010 with respect to the 8.25% Senior Notesdue 2020, and the Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021), incorporated by reference to Exhibit4.4 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.184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, 2010.10.5 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, 2010.10.6 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, 2008.10.7 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, 2008.10.8 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, 2008.10.9 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, 2008.10.10 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, 2010.18510.11 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, 2010.10.12 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, 2011.10.13 Seventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of March 30, 2012, among CNX FundingCorporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, theConduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, theLC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank,incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2012 (file no. 001-14901), filed on April 30, 2012.10.14 Letter Agreement re: Receivables Purchase Agreement - Dilution Ratio, dated June 21, 2012, incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2012 (file no. 001-14901), filed on August 1, 2012.10.15 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, 2010.10.16 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).10.17 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 18,2011.186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 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, 2011.10.27 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, 2011.10.28 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, 2011.10.29 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, incorporated by reference to Exhibit 10.29 to Form 10-K for the yearended December 31, 2012 (file no. 01-14901), filed on February 7, 2013.10.30 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, 2010.10.31 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, 2010.10.32 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, 2010.10.33 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, 2011.10.34 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, 2011.10.35 Successor Agent Agreement, dated as of April 12, 2011, by and among Wilmington Trust Company and David A. Vanaskey 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, 2011.10.36 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, 2011.10.37 Amendment No. 2 to Credit Agreement, dated as of March 12, 2013, to the Amended and Restated Credit Agreement, dated as of April 12,2011, as amended by Amendment No. 1, dated December 14, 2011, by and among CNX Gas Corporation, the lenders and agents party theretoand PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) forthe quarter ended March 31, 2013, filed on May 7, 2013.10.38 Stipulation and Agreement of Compromise and Settlement, dated May 8, 2013, between and among (i) plaintiffs Harold L. Hurwitz and JamesR. Gummel, on their own behalf and on behalf of the Class (as defined therein) and (ii) defendants CNX Gas Corporation, CONSOL EnergyInc. and certain individual defendants, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended June30, 2013, filed on August 5, 2013.18710.39 Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC andNoble Energy, Inc, incorporated by reference to Exhibit 10.2 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed onAugust 5, 2013.10.40 Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and among CNX FundingCorporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listedon the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto,Market Street Funding LLC, as Assignor, and PNC Bank, National Association, as Administrator, as LC Bank and as Assignee, incorporatedby reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2013, filed on November 1, 2013.10.41 Amendment No. 1 to Credit Agreement, dated as of December 5, 2013, to the Amended and Restated Credit Agreement, dated as of April 12,2011, by and among CONSOL Energy Inc., the lenders and agents party thereto and PNC Bank, National Association, as administrativeagent, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on December 11, 2013.10.42 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, 2009.10.43 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, 2007.10.44 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, 2010.10.45 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, 2007.10.46 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, 2005.10.47 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, 2009.10.48 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, 2009.10.49 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, 2009.10.50 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, 2009.10.51 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, 2009.10.52 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, 2009.10.53 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, 2010.10.54 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, 2009.10.55 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, 2009.10.56 Equity Incentive Plan, As Amended and Restated, effective May 1, 2012 incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on March 21, 2012.10.57 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, 2010.10.58 Long-Term Incentive Program (2011 - 2013) (corrected for typographical error), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no.001-14901) for the quarter ended March 31, 2012, filed on April 30, 2012.18810.59 Long-Term Incentive Program (2012 - 2014), incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter endedMarch 31, 2012, filed on April 30, 2012.10.60 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 Form of Performance Share Unit Award Agreement, incorporated by reference to Exhibit 10.4 to Form 10-Q (file no. 001-14901) for the quarterended March 31, 2012, filed on April 30, 2012.10.69 Summary of Non-Employee Director Compensation.10.70 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, 2008.10.71 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, 2008.10.72 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, 2008.10.73 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, 2008.10.74 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, 2006.10.75 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, 2008.10.76 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, 2008.10.77 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, 2009.10.78 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, 2009.10.79 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, 2011.10.80 Discretionary Bonus Agreement - William J. Lyons, dated as of December 19, 2012, incorporated by reference to Exhibit 10.80 to Form 10-K(file no. 001-14901) for the year ended December 31, 2012, filed on February 7, 2013.10.81 Form of CONSOL Stock Unit Award Agreement under the Equity Incentive Plan, incorporated by reference to Exhibit 10.2 to Form 10-Q (fileno. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.10.82 Amended and Restated CONSOL Energy Inc. Executive Annual Incentive Plan, incorporated by reference to Appendix A to the Form DEF 14A(file no. 001-14901) filed on March 29, 2013.10.83 Retirement Letter, dated January 29, 2013, by and between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit10.3 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.18910.84 Retirement and Consulting Agreement, dated February 28, 2013, by and between CONSOL Energy Inc. and William J. Lyons, incorporated byreference to Exhibit 10.4 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.10.85 Retirement and Consulting Agreement, dated February 20, 2013, by and between CONSOL Energy Inc. and Robert F. Pusateri, incorporated byreference to Exhibit 10.5 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.12 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 of200295 Mine Safety Disclosure Exhibit99 Engineers' Audit Letter101 Interactive Data File (Form 10-K for the year ended December 31, 2013 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.190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 7th day of February, 2014. 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 7th day of February, 2014, 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 (Duly Authorized Officer and Principal Executive Officer) /s/ DAVID M. KHANI Chief Financial Officer and Executive Vice PresidentDavid M. Khani (Duly Authorized Officer and Principal Financial Officer) /s/ LORRAINE L. RITTER Controller and Vice PresidentLorraine L. Ritter (Duly Authorized Officer and Principal Accounting Officer) /S/ PHILIP W. BAXTER Lead Independent DirectorPhilip W. Baxter /S/ JAMES E. ALTMEYER, SR. DirectorJames E. Altmeyer, Sr. /s/ ALVIN R. CARPENTER DirectorAlvin R. Carpenter /S/ WILLIAM E. DAVIS DirectorWilliam E. Davis /S/ RAJ K. GUPTA DirectorRaj K. Gupta /S/ DAVID C. HARDESTY, JR. DirectorDavid C. Hardesty, Jr. /s/ MAUREEN E. LALLY-GREEN DirectorMaureen E. Lally-Green /S/ JOHN T. MILLS DirectorJohn T. Mills /s/ WILLIAM P. POWELL DirectorWilliam P. Powell /S/ JOSEPH T. WILLIAMS DirectorJoseph T. Williams 191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, 2013 State operating loss carry-forwards $7,793 $1,987 $(1,410) $(843) $7,527 Deferred deductible temporary differences 170 — — (165) 5 Total $7,963 $1,987 $(1,410) $(1,008) $7,532 Year Ended December 31, 2012 State operating loss carry-forwards $7,801 $224 $(232) $— $7,793 Deferred deductible temporary differences 72 153 (55) — 170 Total $7,873 $377 $(287) $— $7,963 Year Ended December 31, 2011 State operating loss carry-forwards $10,147 $301 $(2,647) $— $7,801 Deferred deductible temporary differences 50 22 — — 72 Total $10,197 $323 $(2,647) $— $7,873192Exhibit 10.69Non-Employee Director Compensation Element of Compensation (Annual) Dollar Value Board Retainer: $120,000 Lead Independent Director Retainer: $30,000 Committee Chair Retainer (other than Audit or Compensation Committees): $10,000 Audit Committee Chair Retainer: $30,000* Compensation Committee Chair Retainer: $20,000 Audit Committee Member Retainer (other than Audit Committee Chair): $7,500 Equity Award: $150,000 ** (in restricted stock units)* Includes Audit Committee member retainer amount (not additional)** Not effective until the May 2014 Annual Meeting of ShareholdersStock Ownership Guidelines: Each director must hold three (3) times the “Annual Board Retainer” in CONSOL Energy Inc.’s common stock (includingany securities convertible or exercisable into its common stock (excluding stock options)) after five (5) years of service on the Board.Exhibit 12Computation of Ratio of Earnings to Fixed Charges(In Thousands) Twelve Months Ended December 31, 2013 2012 2011 2010 2009Earnings: Income from continuing operations before income taxes $46,075 $406,687 $872,925 $430,958 $737,217 Fixed charges, as shown below 292,958 285,784 289,123 240,177 61,573 Equity in income of investees (33,133) (27,048) (24,663) (21,428) (15,707) Noncontrolling Interest 1,386 397 — (11,845) (27,425)Adjusted Earnings $307,286 $665,820 $1,137,385 $637,862 $755,658 Fixed charges: Interest on indebtedness, expensed or capitalized $262,915 $258,096 $263,891 $218,425 $43,290 Interest within rent expense 30,043 27,688 25,232 21,752 18,283Total Fixed Charges $292,958 $285,784 $289,123 $240,177 $61,573 Ratio of Earnings to Fixed Charges 1.052.33 3.93 2.66 12.27Exhibit 21CONSOL Energy Inc.SUBSIDIARIESAs of January 31, 2014(In alphabetical order)AMVEST Coal & Rail, LLC (a Virginia limited liability company) CONSOL of Central Pennsylvania LLC (a Pennsylvania limitedAMVEST Coal Sales, Inc. (a Virginia corporation) liability company)AMVEST Corporation (a Virginia corporation) CONSOL of Kentucky Inc. (a Delaware corporation)AMVEST Gas Resources, Inc. (a Virginia corporation) CONSOL of Ohio LLC (an Ohio limited liability company)AMVEST Mineral Services, Inc. (a Virginia corporation) Consol Pennsylvania Coal Company LLC (formerly ConsolAMVEST Minerals Company, LLC (a Virginia limited liability Pennsylvania Coal Company) (a Delaware limited liabilitycompany) company)AMVEST Oil & Gas, Inc. (a Virginia corporation) Fairmont Supply Company (a Delaware corporation)AMVEST West Virginia Coal, LLC (a West Virginia limited Fairmont Supply Oil and Gas LLC (formerly North Pennliability company) Pipe & Supply, LLC) (a Pennsylvania limited liability company)Braxton-Clay Land & Mineral, Inc. (a West Virginia corporation) Fola Coal Company, LLC d/b/a Powellton Coal Company (a WestCardinal States Gathering Company (a Virginia general partnership) Virginia limited liability company)CNX Funding Corporation (a Delaware corporation) Glamorgan Coal Company, LLC (a Virginia limited liabilityCNX Gas Company LLC (a Virginia limited liability company) company)CNX Gas Corporation (a Delaware corporation) Helvetia Coal Company (a Pennsylvania corporation)CNX Land LLC (a Delaware limited liability company) Island Creek Coal Company (a Delaware corporation)CNX Marine Terminals Inc. (formerly Consolidation Knox Energy, LLC (a Tennessee limited liability company)Coal Sales Company) (a Delaware corporation) Laurel Run Mining Company (a Virginia corporation)CNX RCPC LLC (a Delaware limited liability company) Leatherwood, Inc. (a Pennsylvania corporation)CNX Water Assets LLC (formerly CONSOL of WV LLC) (a West Little Eagle Coal Company, L.L.C. (a West Virginia limited liabilityVirginia limited liability company) company)Coalfield Pipeline Company (a Tennessee corporation) MOB Corporation (a Pennsylvania corporation)Conrhein Coal Company (a Pennsylvania general partnership) Mon-View, LLC (a West Virginia limited liability company)CONSOL Amonate Facility LLC (a Delaware limited liability MTB, Inc. (a Delaware corporation)company) Nicholas-Clay Land & Mineral, Inc. (a Virginia corporation)CONSOL Amonate Mining Company LLC (a Delaware limited Panda Bamboo Holdings, Inc. (a Delaware corporation)liability company) Paros Corp. (a Delaware corporation)CONSOL Buchanan Mining Company LLC (a Delaware limited Peters Creek Mineral Services, Inc. (a Virginia corporation)liability company) Piping and Equipment, Inc. (a Florida corporation)CONSOL Energy Canada Ltd. (a Canadian corporation) R&PCC LLC (a Pennsylvania limited liability company)CONSOL Energy Holdings LLC VI (a Delaware limited liability TEAGLE Company, LLC (a Virginia limited liability company)company) TECPART Corporation (a Delaware corporation)CONSOL Energy Sales Company (formerly CONSOL Sales Terra Firma Company (a West Virginia corporation)Company) (a Delaware corporation) Terry Eagle Coal Company, L.L.C. (a West Virginia limited liabilityCONSOL Financial Inc. (a Delaware corporation) company)CONSOL Mining Company LLC (a Delaware limited liability Terry Eagle Limited Partnership (a West Virginia limitedcompany) partnership)CONSOL Mining Holding Company LLC (a Delaware limited Vaughan Railroad Company (a West Virginia corporation)liability company) Windsor Coal Company (a West Virginia corporation)CONSOL of Canada Inc. (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. and Subsidiaries andin the Registration Statements on Form S-8 (File No. 333-183039, File No. 333-167892, File No. 333-126057, File No. 333-126056, File No. 333-113973, FileNo. 333-87545, File No. 333-160273, and File No. 333-177023) of CONSOL Energy Inc. and Subsidiaries of our reports dated February 7, 2014, withrespect to the consolidated financial statements and schedule of CONSOL Energy Inc. and Subsidiaries and the effectiveness of internal control over financialreporting of CONSOL Energy Inc. and Subsidiaries included in this Annual Report (Form 10-K) for the year ended December 31, 2013. /s/ Ernst & Young, LLPPittsburgh, PennsylvaniaFebruary 7, 2014Consent 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 (includingcoalbed methane) of CONSOL Energy, Inc. as of December 31, 2013 (b) the references to us as experts in CONSOL Energy Inc.'s Annual Reporton Form 10-K for the year ended December 31, 2013 and (c) the incorporation by reference of our name and our audit letter into CONSOL EnergyInc's Registration Statements on Form S-8 (File No. 333-183039, File No. 333-167892, File No. 333-160273, File No. 333-126056, FileNo. 333-113973, File No. 333-87545 and 333-177023) 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 5, 2014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 7, 2014 /s/ J. Brett Harvey J. Brett Harvey Chairman of the Board and Chief Executive Officer (Principal Executive Officer) Exhibit 31.2CERTIFICATIONS I, David M. Khani, 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 7, 2014 /s/ David M. Khani David M. Khani Chief Financial Officer and Executive Vice President(Principal Financial Officer ) 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, 2013, 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 7, 2014 /s/ J. Brett Harvey J. Brett Harvey Chairman of the Board and Chief Executive Officer (Principal Executive Officer) Exhibit 32.2CERTIFICATIONPursuant to Section 906 of the Sarbanes-Oxley Act of 2002,18 U.S.C. Section 1350I, David M. Khani, 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, 2013, 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 7, 2014 /s/ David M. Khani David M. Khani Chief Financial Officer and Executive Vice President(Principal Financial Officer) Exhibit 99February 5, 2014Mr. 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, 2013, 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 estimated herein constitute all of the proved reserves owned by CONSOL. We have examined the estimates with respect to reserves quantities, reservescategorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securitiesand Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with thedefinitions 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, 2013, for the audited properties: Net Reserves Future Net Revenue (M$) Oil NGL Gas Present WorthCategory (MBBL) (MBBL) (MMCF) Total at 10%Proved Developed Producing 1,320.444 4,774.494 2,316,099.000 4,774,610.352 2,112,931.219Proved Developed Non-Producing 54.407 1,164.379 154,312.984 433,154.688 150,869.703Proved Undeveloped (1) 1,430.883 15,606.579 3,114,694.750 5,385,994.000 516,093.094Total Proved 2,805.734 21,545.469 5,585,107.000 10,593,759.000 2,779,893.750Totals may not add because of rounding.(1) These reserves have been included based on the operators' declared intent to drill these wells.The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrelis equivalent 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, 2013, 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. CONSOL has included estimatesof proved undeveloped reserves for certain locations that generate positive future net revenue but have negative present worth discounted at 10 percent based onthe constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators' declared intent todrill these wells, as evidenced by CONSOL's internal budget, reserves estimates, and priceforecast. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Theestimates of reserves and future revenue included 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 2013. For oil and NGL volumes, the average West Texas Intermediate spot price of $96.91 per barrel is adjusted for quality, transportationfees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.670 per MMBTU is adjusted for energy content, transportationfees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted byproduction over the remaining lives of the properties are $81.81 per barrel of oil, $53.03 per barrel of NGL, and $3.62 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. Operating costs have been divided into per-well costsand per-unit-of-production costs. Headquarters general and administrative overhead expenses of CONSOL are included to the extent that they are covered underjoint operating agreements for the operated properties. Capital costs used by CONSOL are based on authorizations for expenditure and actual costs from recentactivity. Capital Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used areCONSOL's estimates of the costs to abandon the wells and production facilities; these estimates do not include any salvage value for the lease and wellequipment. Operating, capital, and abandonment costs are not escalated for inflation.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-2699 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: February 5, 2014 Date Signed: February 5, 2014 RBT:DEG SUMMARY OF NET RESERVES AND FUTURE REVENUECONSOL ENERGY INC. INTERESTAS OF DECEMBER 31, 2013 Investment Net Reserves Future Operating Including Future Net Revenue (M$) Oil NGL Gas Gross Revenue Expense Taxes Abandonment DiscountedCategory (MBBL) (MBBL) (MMCF) (M$) (M$) (M$) (M$) Total At 10%Proved DevelopedProducing 1,320.444 4,774.494 2,316,099.000 8,491,987.000 3,222,514.750 310,286.031 268,105.688 4,691,081.000 2,026,466.500Other Revenue andCosts (1) — — — 141,340.750 57,811.406 — — 83,529.352 86,464.719Total Proved DevelopedProducing 1,320.444 4,774.494 2,316,099.000 8,633,327.750 3,280,326.156 310,286.031 268,105.688 4,774,610.352 2,112,931.219 Proved Developed Non-Producing 54.407 1,164.379 154,312.984 661,369.500 150,534.438 13,460.077 64,220.324 433,154.688 150,869.703 Proved Undeveloped (2) 1,430.883 15,606.597 3,114,694.750 12,307,897.000 2,794,338.750 557,016.562 3,570,547.750 5,385,994.000 516,093.094 Total Proved 2,805.734 21,545.469 5,585,107.000 21,602,594.000 6,225,199.000 880,762.688 3,902,873.500 10,593,759.000 2,779,893.750Totals may not add because of rounding.(1) Other revenue and costs include gas contract revenue and pipeline lease costs.(2) These reserves have been included based on the operators' declared intent to drill these wells. 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, 2013 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, 2013) 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 Alma No. 1 Mine 46-09277 7 — — — — $6,104 — No No — — —Bailey 36-07230 77 — — — — $185,163 — No No 12 2 1Buchanan 44-04856 67 — — — — $363,835 — No No 34 2 2Enlow Fork 36-07416 68 — 2 — — $145,446 — No No 9 3 1Miller Creek PP #1 46-05890 11 — — — — $7,024 — No No — — 1Twin Branch Surface 46-09075 2 — — — — $663 — No No — — — Inactive Operations Amonate 46-05449 — — — — — $100 — No No — — —Big Branch#1Belt/Spruce Creek 46-09177 — — — — — $— — No No — — —Bronzite II (MT-41) 46-09307 — — — — — $1,111 — No No — — —Bronzite III (Jacobs) 46-05978 — — — — — $833 — No No — — —Emery 42-00079 — — — — — $200 — No No — — —Fola Surface 46-08377 — — — — — $— — No No — — —Ike Fork (5 BlockMine) 46-09420 — — — — — $648 — No No 1 — —Impoundment 14-N 36-08094 — — — — — $— — No No — — —Laurel Fork 46-09084 2 — — — — $1,021 — No No — — —Lick Branch 46-08676 — — — — — $772 — No No — — —Little Eagle Mine #1 46-08560 — — — — — $— — No No — — —Meigs #31 Mine 33-01172 — — — — — $— — No No — — —Miles Branch 44-03932 — — — — — $— — No No — — —Minway Surface 46-06089 — — — — — $— — No No — — —MT-34UG 46-09424 — — — — — $10,171 — No No — — —Muskingum 33-00989 — — — — — $— — No No — — —2Peach Orchard PrepPlant 46-08376 — — — — — $200 — No No — — —Powellton/BridgeFork 46-08889 — — — — — $— — No No — — —Reclamation #061 33-00962 — — — — — $— — No No — — —Robena Prep 36-04175 — — — — — $300 — No No — — —Rock Lick 46-09171 — — — — — $— — No No — — —Terry Eagle PP #1 46-02295 — — — — — $— — No No — — —Wiley Creek (MT-13/500) 46-09185 — — — — — $705 — No No — — —WileySurface(MT34/PegFork) 46-09035 3 — — — — $3,624 — No No — — —Winoc Prep Plant 46-08172 — — — — — $— — No No — — — 237 — 2 — — $727,920 — 56 7 5(1) See table below for additional detail regarding Legal Actions Pending as of December 31, 2013. With respect to Contests of Proposed Penalties, we haveincluded the number of dockets (as opposed to citations) when counting the number of Legal Actions Pending as of December 31, 2013.3Mine or Operating Name/MSHA IdentificationNumber Contests ofCitations,Orders(as of 12.31.13)(a) Contests of Proposed Penalties(as of 12.31.13)(b) Complaints forCompensation(as of 12.31.13)(c) Complaints ofDischarge,Discriminationor Interference(as of 12.31.13)(d) Applicationsfor TemporaryRelief(as of 12.31.13)(e) Appeals ofJudges'Decisions orOrder(as of12.31.13)(f) Dockets Citations Active Operations Alma No. 1 Mine 46-09277 — — — — — — —Bailey 36-07230 — 12 36 — 2 — —Buchanan 44-04856 — 34 281 — 2 — —Enlow Fork 36-07416 — 9 34 — — — —Miller Creek PP #1 46-05890 — — — — — — —Twin Branch Surface 46-09075 — — — — — — — Inactive Operations Amonate 46-05449 — — — — — — —Big Branch #1Belt/Spruce Creek 46-09177 — — — — — — —Bronzite II (MT‑41) 46-09307 — — — — — — —Bronzite III (Jacobs) 46-05978 — — — — — — —Emery 42-00079 — — — — — — —Fola Surface 46-08377 — — — — — — —Ike Fork (5 Block Mine) 46-09420 — 1 1 — — — —Impoundment 14‑N 36-08094 — — — — — — —Laurel Fork 46-09084 — — — — — — —Lick Branch 46-08676 — — — — — — —Little Eagle Mine #1 46-08560 — — — — — — —Meigs #31 Mine 33-01172 — — — — — — —Miles Branch 44-03932 — — — — — — —Minway Surface 46-06089 — — — — — — —MT-34UG 46-09424 — — — — — — —Muskingum 33-00989 — — — — — — —Peach Orchard Prep Plant 46-08376 — — — — — — —Powellton/Bridge Fork 46-08889 — — — — — — —Reclamation #061 33-00962 — — — — — — —4Robena Prep 36-04175 — — — — — — —Rock Lick 46-09171 — — — — — — —Terry Eagle PP #1 46-02295 — — — — — — —Wiley (MT‑11) 46-09138 — — — — — — —Wiley Surface(MT34/Peg Fork) 46-09035 — — — — — — —Winoc Prep Plant 46-08172 — — — — — — — — 56 352 — 4 — —(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.5

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